Patent Description:
The directional driller makes use of a range of technologies to steer the well. Components may be added to the bottom hole assembly (BHA) to allow the directional driller to control the position of the BHA and, as a result, the well path being created using the BHA. For example, motors may be used with a bent motor housing in the BHA to steer the BHA by alternating intervals of sliding and rotating. Rotary steerable systems (RSSs) can also be used to steer the BHA. Other advances (such as hybrid RSSs) can also be used to direct the BHA and create a directional well.

Prior to beginning to drill a well, a team usually creates a directional drilling well plan. A well plan is the description of proposed wellbore, which description will be used by the drilling team in drilling the well. The well plan typically includes information about the shape, orientation, depth, completion, and evaluation along with information about the equipment to used, actions to be taken at different points in the well construction process, and other information the team planning the well believes will be relevant to the team drilling the well.

The position of the BHA, and thus the path of the well, is typically measured at various points during creation of the well and compared to the expected position of the BHA as per the planned trajectory specified in the well plan. When the position of the BHA is off the planned trajectory, software supporting the directional drilling effort may generate and propose a correctional trajectory to move the BHA from its current position to the planned trajectory.

Given that the directional driller generally has substantial experience in drilling directional wells, the directional driller may not want to use the generated correctional trajectory. What is needed is a system and method that allows the directional driller to effectively explore additional options before deciding how to get back to the planned trajectory.

<CIT> describes a method comprising receiving information that comprises well trajectory information, wellsite equipment information and driller information, based at least in part on the information, determining a level of detail of human executable well plan instructions, based at least in part on the information, generating a well plan wherein the well plan comprises human executable well plan instructions based on the determined level of detail and outputting the well plan.

The present invention resides in a method as defined in claim <NUM>, a drilling system as defined in claim <NUM> and a non-transitory computer-readable medium as defined in claim <NUM>.

The figures below are not necessarily to scale; dimensions may altered to help clarify or emphasize certain features.

The following detailed description refers to the accompanying drawings. Wherever convenient, the same reference numbers are used in the drawings and the following description to refer to the same or similar parts. While several embodiments and features of the present disclosure are described herein, modifications, adaptations, and other implementations are possible, without departing from the scope of the present disclosure.

Although the terms "first", "second", etc. may be used herein to describe various elements, these terms are used to distinguish one element from another. For example, a first object or step could be termed a second object or step, and, similarly, a second object or step could be termed a first object or step, without departing from the scope of the present disclosure. The first object or step, and the second object or step, are both, objects or steps, respectively, but they are not to be considered the same object or step.

The terminology used in the description herein is for the purpose of describing particular embodiments and is not intended to be limiting. As used in this description and the appended claims, the singular forms "a," "an" and "the" are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will also be understood that the term "and/or" as used herein refers to and encompasses any possible combinations of one or more of the associated listed items. It will be further understood that the terms "includes," "including," "comprises" and/or "comprising," when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof. Further, as used herein, the term "if" may be construed to mean "when" or "upon" or "in response to determining" or "in response to detecting," depending on the context.

<FIG> illustrates one example of an environment <NUM> in which drilling may occur. The environment may include a reservoir <NUM> and various geological features, such as stratified layers. The geological aspects of the environment <NUM> may contain other features such as faults, basins, and others. The reservoir <NUM> may be located on land or offshore.

The environment <NUM> may be outfitted with sensors, detectors, actuators, etc. to be used in connection with the drilling process. <FIG> illustrates equipment <NUM> associated with a well <NUM> being constructed using downhole equipment <NUM>. The downhole equipment <NUM> may be, for example, part of a bottom hole assembly (BHA). The BHA may be used to drill the well <NUM>. The downhole equipment <NUM> may communicate information to the equipment <NUM> at the surface, and may receive instructions and information from the surface equipment <NUM> as well. The surface equipment <NUM> and the downhole equipment <NUM> may communicate using various communications techniques, such as mud-pulse telemetry, electromagnetic (EM) telemetry, or others depending on the equipment and technology in use for the drilling operation.

The surface equipment <NUM> may also include communications means to communicate over a network <NUM> to remote computing devices <NUM>. For example, the surface equipment <NUM> may communicate data using a satellite network to computing devices <NUM> supporting a remote team monitoring and assisting in the creation of the well <NUM> and other wells in other locations. Depending on the communications infrastructure available at the wellsite, various communications equipment and techniques (cellular, satellite, wired Internet connection, etc.) may be used to communicate data from the surface equipment <NUM> to the remote computing devices <NUM>. In some embodiments, the surface equipment <NUM> sends data from measurements taken at the surface and measurements taken downhole by the downhole equipment <NUM> to the remote computing devices <NUM>.

During the well construction process, a variety of operations (such as cementing, wireline evaluation, testing, etc.) may also be conducted. In such embodiments, the data collected by tools and sensors and used for reasons such as reservoir characterization may also be collected and transmitted by the surface equipment <NUM>.

In <FIG>, the well <NUM> includes a substantially horizontal portion (e.g., lateral portion) that may intersect with one or more fractures. For example, a well in a shale formation may pass through natural fractures, artificial fractures (e.g., hydraulic fractures), or a combination thereof. Such a well may be constructed using directional drilling techniques as described herein. However, these same techniques may be used in connection with other types of directional wells (such as slant wells, S-shaped wells, deep inclined wells, and others) and are not limited to horizontal wells.

<FIG> shows an example of a wellsite system <NUM> (e.g., at a wellsite that may be onshore or offshore). As shown, the wellsite system <NUM> can include a mud tank <NUM> for holding mud and other material (e.g., where mud can be a drilling fluid), a suction line <NUM> that serves as an inlet to a mud pump <NUM> for pumping mud from the mud tank <NUM> such that mud flows to a vibrating hose <NUM>, a drawworks <NUM> for winching drill line or drill lines <NUM>, a standpipe <NUM> that receives mud from the vibrating hose <NUM>, a kelly hose <NUM> that receives mud from the standpipe <NUM>, a gooseneck or goosenecks <NUM>, a traveling block <NUM>, a crown block <NUM> for carrying the traveling block <NUM> via the drill line or drill lines <NUM> (see, e.g., the crown block <NUM> of <FIG>), a derrick <NUM> (see, e.g., the derrick <NUM> of <FIG>), a kelly <NUM> or a top drive <NUM>, a kelly drive bushing <NUM>, a rotary table <NUM>, a drill floor <NUM>, a bell nipple <NUM>, one or more blowout preventors (BOPs) <NUM>, a drillstring <NUM>, a drill bit <NUM>, a casing head <NUM> and a flow pipe <NUM> that carries mud and other material to, for example, the mud tank <NUM>.

In the example system of <FIG>, a borehole <NUM> is formed in subsurface formations <NUM> by rotary drilling; noting that various example embodiments may also use one or more directional drilling techniques, equipment, etc..

As shown in the example of <FIG>, the drillstring <NUM> is suspended within the borehole <NUM> and has a drillstring assembly <NUM> that includes the drill bit <NUM> at its lower end. As an example, the drillstring assembly <NUM> may be a bottom hole assembly (BHA).

The wellsite system <NUM> can provide for operation of the drillstring <NUM> and other operations. As shown, the wellsite system <NUM> includes the traveling block <NUM> and the derrick <NUM> positioned over the borehole <NUM>. As mentioned, the wellsite system <NUM> can include the rotary table <NUM> where the drillstring <NUM> pass through an opening in the rotary table <NUM>.

As shown in the example of <FIG>, the wellsite system <NUM> can include the kelly <NUM> and associated components, etc., or a top drive <NUM> and associated components. As to a kelly example, the kelly <NUM> may be a square or hexagonal metal/alloy bar with a hole drilled therein that serves as a mud flow path. The kelly <NUM> can be used to transmit rotary motion from the rotary table <NUM> via the kelly drive bushing <NUM> to the drillstring <NUM>, while allowing the drillstring <NUM> to be lowered or raised during rotation. The kelly <NUM> can pass through the kelly drive bushing <NUM>, which can be driven by the rotary table <NUM>. As an example, the rotary table <NUM> can include a master bushing that operatively couples to the kelly drive bushing <NUM> such that rotation of the rotary table <NUM> can turn the kelly drive bushing <NUM> and hence the kelly <NUM>. The kelly drive bushing <NUM> can include an inside profile matching an outside profile (e.g., square, hexagonal, etc.) of the kelly <NUM>; however, with slightly larger dimensions so that the kelly <NUM> can freely move up and down inside the kelly drive bushing <NUM>.

As to a top drive example, the top drive <NUM> can provide functions performed by a kelly and a rotary table. The top drive <NUM> can turn the drillstring <NUM>. As an example, the top drive <NUM> can include one or more motors (e.g., electric and/or hydraulic) connected with appropriate gearing to a short section of pipe called a quill, that in turn may be screwed into a saver sub or the drillstring <NUM> itself. The top drive <NUM> can be suspended from the traveling block <NUM>, so the rotary mechanism is free to travel up and down the derrick <NUM>. As an example, a top drive <NUM> may allow for drilling to be performed with more joint stands than a kelly/rotary table approach.

In the example of <FIG>, the mud tank <NUM> can hold mud, which can be one or more types of drilling fluids. As an example, a wellbore may be drilled to produce fluid, inject fluid or both (e.g., hydrocarbons, minerals, water, etc.).

In the example of <FIG>, the drillstring <NUM> (e.g., including one or more downhole tools) may be composed of a series of pipes threadably connected together to form a long tube with the drill bit <NUM> at the lower end thereof. As the drillstring <NUM> is advanced into a wellbore for drilling, at some point in time prior to or coincident with drilling, the mud may be pumped by the pump <NUM> from the mud tank <NUM> (e.g., or other source) via a the lines <NUM>, <NUM> and <NUM> to a port of the kelly <NUM> or, for example, to a port of the top drive <NUM>. The mud can then flow via a passage (e.g., or passages) in the drillstring <NUM> and out of ports located on the drill bit <NUM> (see, e.g., a directional arrow). As the mud exits the drillstring <NUM> via ports in the drill bit <NUM>, it can then circulate upwardly through an annular region between an outer surface(s) of the drillstring <NUM> and surrounding wall(s) (e.g., open borehole, casing, etc.), as indicated by directional arrows. In such a manner, the mud lubricates the drill bit <NUM> and carries heat energy (e.g., frictional or other energy) and formation cuttings to the surface where the mud (e.g., and cuttings) may be returned to the mud tank <NUM>, for example, for recirculation (e.g., with processing to remove cuttings, etc.).

The mud pumped by the pump <NUM> into the drillstring <NUM> may, after exiting the drillstring <NUM>, form a mudcake that lines the wellbore which, among other functions, may reduce friction between the drillstring <NUM> and surrounding wall(s) (e.g., borehole, casing, etc.). A reduction in friction may facilitate advancing or retracting the drillstring <NUM>. During a drilling operation, the entire drillstring <NUM> may be pulled from a wellbore and optionally replaced, for example, with a new or sharpened drill bit, a smaller diameter drillstring, etc. As mentioned, the act of pulling a drillstring out of a hole or replacing it in a hole is referred to as tripping. A trip may be referred to as an upward trip or an outward trip or as a downward trip or an inward trip depending on trip direction.

As an example, consider a downward trip where upon arrival of the drill bit <NUM> of the drillstring <NUM> at a bottom of a wellbore, pumping of the mud commences to lubricate the drill bit <NUM> for purposes of drilling to enlarge the wellbore. As mentioned, the mud can be pumped by the pump <NUM> into a passage of the drillstring <NUM> and, upon filling of the passage, the mud may be used as a transmission medium to transmit energy, for example, energy that may encode information as in mud-pulse telemetry.

As an example, mud-pulse telemetry equipment may include a downhole device configured to effect changes in pressure in the mud to create an acoustic wave or waves upon which information may modulated. In such an example, information from downhole equipment (e.g., one or more modules of the drillstring <NUM>) may be transmitted uphole to an uphole device, which may relay such information to other equipment for processing, control, etc..

As an example, telemetry equipment may operate via transmission of energy via the drillstring <NUM> itself. For example, consider a signal generator that imparts coded energy signals to the drillstring <NUM> and repeaters that may receive such energy and repeat it to further transmit the coded energy signals (e.g., information, etc.).

As an example, the drillstring <NUM> may be fitted with telemetry equipment <NUM> that includes a rotatable drive shaft, a turbine impeller mechanically coupled to the drive shaft such that the mud can cause the turbine impeller to rotate, a modulator rotor mechanically coupled to the drive shaft such that rotation of the turbine impeller causes said modulator rotor to rotate, a modulator stator mounted adjacent to or proximate to the modulator rotor such that rotation of the modulator rotor relative to the modulator stator creates pressure pulses in the mud, and a controllable brake for selectively braking rotation of the modulator rotor to modulate pressure pulses. In such example, an alternator may be coupled to the aforementioned drive shaft where the alternator includes at least one stator winding electrically coupled to a control circuit to selectively short the at least one stator winding to electromagnetically brake the alternator and thereby selectively brake rotation of the modulator rotor to modulate the pressure pulses in the mud.

In the example of <FIG>, an uphole control and/or data acquisition system <NUM> may include circuitry to sense pressure pulses generated by telemetry equipment <NUM> and, for example, communicate sensed pressure pulses or information derived therefrom for process, control, etc..

The assembly <NUM> of the illustrated example includes a logging-while-drilling (LWD) module <NUM>, a measurement-while-drilling (MWD) module <NUM>, an optional module <NUM>, a rotary-steerable system (RSS) and/or motor <NUM>, and the drill bit <NUM>. Such components or modules may be referred to as tools where a drillstring can include a plurality of tools.

As to a RSS, it involves technology utilized for directional drilling. Directional drilling involves drilling into the Earth to form a deviated bore such that the trajectory of the bore is not vertical; rather, the trajectory deviates from vertical along one or more portions of the bore. As an example, consider a target that is located at a lateral distance from a surface location where a rig may be stationed. In such an example, drilling can commence with a vertical portion and then deviate from vertical such that the bore is aimed at the target and, eventually, reaches the target. Directional drilling may be implemented where a target may be inaccessible from a vertical location at the surface of the Earth, where material exists in the Earth that may impede drilling or otherwise be detrimental (e.g., consider a salt dome, etc.), where a formation is laterally extensive (e.g., consider a relatively thin yet laterally extensive reservoir), where multiple bores are to be drilled from a single surface bore, where a relief well is desired, etc..

One approach to directional drilling involves a mud motor; however, a mud motor can present some challenges depending on factors such as rate of penetration (ROP), transferring weight to a bit (e.g., weight on bit, WOB) due to friction, etc. A mud motor can be a positive displacement motor (PDM) that operates to drive a bit (e.g., during directional drilling, etc.). A PDM operates as drilling fluid is pumped through it where the PDM converts hydraulic power of the drilling fluid into mechanical power to cause the bit to rotate.

As an example, a PDM may operate in a combined rotating mode where surface equipment is utilized to rotate a bit of a drillstring (e.g., a rotary table, a top drive, etc.) by rotating the entire drillstring and where drilling fluid is utilized to rotate the bit of the drillstring. In such an example, a surface RPM (SRPM) may be determined by use of the surface equipment and a downhole RPM of the mud motor may be determined using various factors related to flow of drilling fluid, mud motor type, etc. As an example, in the combined rotating mode, bit RPM can be determined or estimated as a sum of the SRPM and the mud motor RPM, assuming the SRPM and the mud motor RPM are in the same direction.

As an example, a PDM mud motor can operate in a so-called sliding mode, when the drillstring is not rotated from the surface. In such an example, a bit RPM can be determined or estimated based on the RPM of the mud motor.

A RSS can drill directionally where there is continuous rotation from surface equipment, which can alleviate the sliding of a steerable motor (e.g., a PDM). A RSS may be deployed when drilling directionally (e.g., deviated, horizontal, or extended-reach wells). A RSS can aim to minimize interaction with a borehole wall, which can help to preserve borehole quality. A RSS can aim to exert a relatively consistent side force akin to stabilizers that rotate with the drillstring or orient the bit in the desired direction while continuously rotating at the same number of rotations per minute as the drillstring.

The LWD module <NUM> may be housed in a suitable type of drill collar and can contain one or a plurality of selected types of logging tools. It will also be understood that more than one LWD and/or MWD module can be employed, for example, as represented at by the module <NUM> of the drillstring assembly <NUM>. Where the position of an LWD module is mentioned, as an example, it may refer to a module at the position of the LWD module <NUM>, the module <NUM>, etc. An LWD module can include capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment. In the illustrated example, the LWD module <NUM> may include a seismic measuring device.

The MWD module <NUM> may be housed in a suitable type of drill collar and can contain one or more devices for measuring characteristics of the drillstring <NUM> and the drill bit <NUM>. As an example, the MWD tool <NUM> may include equipment for generating electrical power, for example, to power various components of the drillstring <NUM>. As an example, the MWD tool <NUM> may include the telemetry equipment <NUM>, for example, where the turbine impeller can generate power by flow of the mud; it being understood that other power and/or battery systems may be employed for purposes of powering various components. As an example, the MWD module <NUM> may include one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device.

<FIG> also shows some examples of types of holes that may be drilled. For example, consider a slant hole <NUM>, an S-shaped hole <NUM>, a deep inclined hole <NUM> and a horizontal hole <NUM>.

As an example, a drilling operation can include directional drilling where, for example, at least a portion of a well includes a curved axis. For example, consider a radius that defines curvature where an inclination with regard to the vertical may vary until reaching an angle between about <NUM> degrees and about <NUM> degrees or, for example, an angle to about <NUM> degrees or possibly greater than about <NUM> degrees.

As an example, a directional well can include several shapes where each of the shapes may aim to meet particular operational demands. As an example, a drilling process may be performed on the basis of information as and when it is relayed to a drilling engineer. As an example, inclination and/or direction may be modified based on information received during a drilling process.

As an example, deviation of a bore may be accomplished in part by use of a downhole motor and/or a turbine. As to a motor, for example, a drillstring can include a positive displacement motor (PDM).

As an example, a system may be a steerable system and include equipment to perform method such as geosteering. As mentioned, a steerable system can be or include an RSS. As an example, a steerable system can include a PDM or of a turbine on a lower part of a drillstring which, just above a drill bit, a bent sub can be mounted. As an example, above a PDM, MWD equipment that provides real time or near real time data of interest (e.g., inclination, direction, pressure, temperature, real weight on the drill bit, torque stress, etc.) and/or LWD equipment may be installed. As to the latter, LWD equipment can make it possible to send to the surface various types of data of interest, including for example, geological data (e.g., gamma ray log, resistivity, density and sonic logs, etc.).

The coupling of sensors providing information on the course of a well trajectory, in real time or near real time, with, for example, one or more logs characterizing the formations from a geological viewpoint, can allow for implementing a geosteering method. Such a method can include navigating a subsurface environment, for example, to follow a desired route to reach a desired target or targets.

As an example, a drillstring can include an azimuthal density neutron (ADN) tool for measuring density and porosity; a MWD tool for measuring inclination, azimuth and shocks; a compensated dual resistivity (CDR) tool for measuring resistivity and gamma ray related phenomena; one or more variable gauge stabilizers; one or more bend joints; and a geosteering tool, which may include a motor and optionally equipment for measuring and/or responding to one or more of inclination, resistivity and gamma ray related phenomena.

As an example, geosteering can include intentional directional control of a wellbore based on results of downhole geological logging measurements in a manner that aims to keep a directional wellbore within a desired region, zone (e.g., a pay zone), etc. As an example, geosteering may include directing a wellbore to keep the wellbore in a particular section of a reservoir, for example, to minimize gas and/or water breakthrough and, for example, to maximize economic production from a well that includes the wellbore.

Referring again to <FIG>, the wellsite system <NUM> can include one or more sensors <NUM> that are operatively coupled to the control and/or data acquisition system <NUM>. As an example, a sensor or sensors may be at surface locations. As an example, a sensor or sensors may be at downhole locations. As an example, a sensor or sensors may be at one or more remote locations that are not within a distance of the order of about one hundred meters from the wellsite system <NUM>. As an example, a sensor or sensor may be at an offset wellsite where the wellsite system <NUM> and the offset wellsite are in a common field (e.g., oil and/or gas field).

As an example, one or more of the sensors <NUM> can be provided for tracking pipe, tracking movement of at least a portion of a drillstring, etc..

As an example, the system <NUM> can include one or more sensors <NUM> that can sense and/or transmit signals to a fluid conduit such as a drilling fluid conduit (e.g., a drilling mud conduit). For example, in the system <NUM>, the one or more sensors <NUM> can be operatively coupled to portions of the standpipe <NUM> through which mud flows. As an example, a downhole tool can generate pulses that can travel through the mud and be sensed by one or more of the one or more sensors <NUM>. In such an example, the downhole tool can include associated circuitry such as, for example, encoding circuitry that can encode signals, for example, to reduce demands as to transmission. As an example, circuitry at the surface may include decoding circuitry to decode encoded information transmitted at least in part via mud-pulse telemetry. As an example, circuitry at the surface may include encoder circuitry and/or decoder circuitry and circuitry downhole may include encoder circuitry and/or decoder circuitry. As an example, the system <NUM> can include a transmitter that can generate signals that can be transmitted downhole via mud (e.g., drilling fluid) as a transmission medium.

As an example, one or more portions of a drillstring may become stuck. The term stuck can refer to one or more of varying degrees of inability to move or remove a drillstring from a bore. As an example, in a stuck condition, it might be possible to rotate pipe or lower it back into a bore or, for example, in a stuck condition, there may be an inability to move the drillstring axially in the bore, though some amount of rotation may be possible. As an example, in a stuck condition, there may be an inability to move at least a portion of the drillstring axially and rotationally.

As to the term "stuck pipe", this can refer to a portion of a drillstring that cannot be rotated or moved axially. As an example, a condition referred to as "differential sticking" can be a condition whereby the drillstring cannot be moved (e.g., rotated or reciprocated) along the axis of the bore. Differential sticking may occur when high-contact forces caused by low reservoir pressures, high wellbore pressures, or both, are exerted over a sufficiently large area of the drillstring. Differential sticking can have time and financial cost.

As an example, a sticking force can be a product of the differential pressure between the wellbore and the reservoir and the area that the differential pressure is acting upon. This means that a relatively low differential pressure (delta p) applied over a large working area can be just as effective in sticking pipe as can a high differential pressure applied over a small area.

As an example, a condition referred to as "mechanical sticking" can be a condition where limiting or prevention of motion of the drillstring by a mechanism other than differential pressure sticking occurs. Mechanical sticking can be caused, for example, by one or more of junk in the hole, wellbore geometry anomalies, cement, keyseats or a buildup of cuttings in the annulus.

<FIG> illustrates a schematic view of such a computing or processor system <NUM>, according to an embodiment. The processor system <NUM> includes one or more processors <NUM> of varying core configurations (including multiple cores) and clock frequencies. The one or more processors <NUM> are operable to execute instructions, apply logic, etc. It will be appreciated that these functions may be provided by multiple processors or multiple cores on a single chip operating in parallel and/or communicably linked together. In at least one embodiment, the one or more processors <NUM> may be or include one or more GPUs.

The processor system <NUM> also includes a memory system, which is or includes one or more memory devices and/or computer-readable media <NUM> of varying physical dimensions, accessibility, storage capacities, etc. such as flash drives, hard drives, disks, random access memory, etc., for storing data, such as images, files, and program instructions for execution by the processor <NUM>. In an embodiment, the computer-readable media <NUM> stores instructions that, when executed by the processor <NUM>, are configured to cause the processor system <NUM> to perform operations. Execution of such instructions causes the processor system <NUM> to implement one or more portions and/or embodiments of the method(s) described above.

The processor system <NUM> may also include one or more network interfaces <NUM>. The network interfaces <NUM> may include any hardware, applications, and/or other software. Accordingly, the network interfaces <NUM> may include Ethernet adapters, wireless transceivers, PCI interfaces, and/or serial network components, for communicating over wired or wireless media using protocols, such as Ethernet, wireless Ethernet, etc..

As an example, the processor system <NUM> may be a mobile device that includes one or more network interfaces for communication of information. For example, a mobile device may include a wireless network interface (e.g., operable via one or more IEEE <NUM> protocols, ETSI GSM, BLUETOOTH®, satellite, etc.). As an example, a mobile device may include components such as a main processor, memory, a display, display graphics circuitry (e.g., optionally including touch and gesture circuitry), a SIM slot, audio/video circuitry, motion processing circuitry (e.g., accelerometer, gyroscope), wireless LAN circuitry, smart card circuitry, transmitter circuitry, GPS circuitry, and a battery. As an example, a mobile device may be configured as a cell phone, a tablet, etc. As an example, a method may be implemented (e.g., wholly or in part) using a mobile device. As an example, a system may include one or more mobile devices.

The processor system <NUM> may further include one or more peripheral interfaces <NUM>, for communication with a display, projector, keyboards, mice, touchpads, sensors, other types of input and/or output peripherals, and/or the like. In some implementations, the components of processor system <NUM> need not be enclosed within a single enclosure or even located in close proximity to one another, but in other implementations, the components and/or others may be provided in a single enclosure. As an example, a system may be a distributed environment, for example, a so-called "cloud" environment where various devices, components, etc. interact for purposes of data storage, communications, computing, etc. As an example, a method may be implemented in a distributed environment (e.g., wholly or in part as a cloud-based service).

As an example, information may be input from a display (e.g., a touchscreen), output to a display or both. As an example, information may be output to a projector, a laser device, a printer, etc. such that the information may be viewed. As an example, information may be output stereographically or holographically. As to a printer, consider a 2D or a 3D printer. As an example, a 3D printer may include one or more substances that can be output to construct a 3D object. For example, data may be provided to a 3D printer to construct a 3D representation of a subterranean formation. As an example, layers may be constructed in 3D (e.g., horizons, etc.), geobodies constructed in 3D, etc. As an example, holes, fractures, etc., may be constructed in 3D (e.g., as positive structures, as negative structures, etc.).

The memory device <NUM> may be physically or logically arranged or configured to store data on one or more storage devices <NUM>. The storage device <NUM> may include one or more file systems or databases in any suitable format. The storage device <NUM> may also include one or more software programs <NUM>, which may contain interpretable or executable instructions for performing one or more of the disclosed processes. When requested by the processor <NUM>, one or more of the software programs <NUM>, or a portion thereof, may be loaded from the storage devices <NUM> to the memory devices <NUM> for execution by the processor <NUM>.

Those skilled in the art will appreciate that the above-described componentry is merely one example of a hardware configuration, as the processor system <NUM> may include any type of hardware components, including any accompanying firmware or software, for performing the disclosed implementations. The processor system <NUM> may also be implemented in part or in
whole by electronic circuit components or processors, such as application-specific integrated circuits (ASICs) or field-programmable gate arrays (FPGAs).

The processor system <NUM> is configured to receive a directional drilling well plan <NUM>. As discussed above, a well plan is to the description of the proposed wellbore to be used by the drilling team in drilling the well. The well plan typically includes information about the shape, orientation, depth, completion, and evaluation along with information about the equipment to be used, actions to be taken at different points in the well construction process, and other information the team planning the well believes will be relevant/helpful to the team drilling the well. A directional drilling well plan will also include information about how to steer and manage the direction of the well.

The processor system <NUM> is configured to receive drilling data <NUM>. The drilling data <NUM> may include data collected by one or more sensors associated with surface equipment or with downhole equipment. The drilling data <NUM> includes data relating to the position of the BHA (such as survey data or continuous position data), drilling parameters (such as weight on bit (WOB), rate of penetration (ROP), torque, or others), text information entered by individuals working at the wellsite, or other data collected during the construction of the well.

In one embodiment, the processor system <NUM> is part of a rig control system (RCS) for the rig. In another embodiment, the processor system <NUM> is a separately installed computing unit including a display that is installed at the rig site and receives data from the RCS. In such an embodiment, the software on the processor system <NUM> may be installed on the computing unit, brought to the wellsite, and installed and communicatively connected to the rig control system in preparation for constructing the well or a portion thereof.

In another embodiment, the processor system <NUM> may be at a location remote from the wellsite and receives the drilling data <NUM> over a communications medium using a protocol such as well-site information transfer specification or standard (WITS) and markup language (WITSML). In such an embodiment, the software on the processor system <NUM> may be a web-native application that is accessed by users using a web browser. In such an embodiment, the processor system <NUM> may be remote from the wellsite where the well is being constructed, and the user may be at the wellsite or at a location remote from the wellsite.

<FIG> illustrates an example of a way to evaluate options for returning a BHA to a planned trajectory. <FIG> illustrates a planned trajectory <NUM> for a well. The planned trajectory <NUM> is typically included as part of the well plan for the well, and is accompanied by a set of instructions for reaching a target location <NUM> for the well using the drilling system such as the one illustrated in <FIG>. While the illustration in <FIG> shows one target location <NUM> specified in the well plan, a well plan may specify multiple target locations.

A computing system, such as the one discussed in connection with <FIG>, may be configured to receive BHA position data from one or more sensors during construction of the well. For example, in drilling a directional well the drilling team may take survey measurements at increments. In certain embodiments, the BHA may include components to take continuous positional measurements and generate continuous positional data for the BHA. Using this BHA position data, the computing system may determine a current position <NUM> of the BHA.

The computing system may compare the current position <NUM> of the BHA with the planned trajectory <NUM>. While a certain degree of deviation from the planned trajectory <NUM> may be acceptable, the computing system may have a threshold value to identify when corrective action is appropriate. In certain embodiments, in response to determining that the current position <NUM> of the BHA is off the planned trajectory <NUM> by a threshold amount (as illustrated in <FIG>), the computing system may notify one or more users and require corrective action.

In one embodiment, the computing system may automatically create a generated correctional trajectory (such as generated correctional trajectory <NUM>) to move the BHA from the current position to the planned trajectory. In the embodiment shown in <FIG>, the generated correctional trajectory <NUM> returns the BHA to the planned trajectory at a point <NUM>. Various approaches and software solutions for automatically creating a generated correctional trajectory <NUM> are known in the art. The computing system may present the generated correctional trajectory <NUM> to one or more users for review and acceptance. The computing system may, for example, present the generated correctional trajectory <NUM> to a directional drilling team at the wellsite, one or more specialists supporting the well construction from a remote location, a representative for the operator, or others.

While the generated correctional trajectory <NUM> may be the best option to return the BHA to the planned trajectory <NUM>, a directional drilling team may want to use a different trajectory or explore different possible trajectories to return to the planned trajectory <NUM>. The directional drilling team may want to modify certain aspects of the generated correctional trajectory <NUM>.

The computing system is configured to facilitate investigation of alternative correctional trajectories. In the embodiment shown in <FIG>, the computing system receives an intermediate target <NUM> from the user. The user specifies one or more positional values for the intermediate target <NUM>. The user may, for example, select a point on a graphical user interface to specify the intermediate target <NUM>. The user may provide one or more positional values for the intermediate target <NUM>. The user may select a point on the planned trajectory <NUM> and drag the point to a different location to create the intermediate target <NUM>. The user may enter one or more coordinate values for the intermediate target <NUM>. In one embodiment, the user may enter desired values for a survey at the intermediate target <NUM> in order to provide the position values. The computing system may identify the position selected by the user on a graphical user interface and associate that position with a number of different position values representing its location.

In one embodiment, the computing system may display one or more of the positional values for the intermediate target <NUM> in an editable format. For example, in an embodiment where the user drags and drops a location from the planned trajectory <NUM> to a new location to create an intermediate target <NUM>, the computing system may display the positional values associated with the location the user set graphically for the intermediate target <NUM>. In such an embodiment, the user may create a first 'estimate' of the position of the intermediate target <NUM> graphically and then edit the positional values for the intermediate target <NUM> to refine its position.

After receiving the intermediate target <NUM>, the computing system generates a candidate correctional trajectory. In embodiments where the user provides an intermediate target <NUM> and one or more child intermediate targets (such as <NUM> and <NUM>. <NUM>) the candidate correctional trajectory may be made up of a number of segments. For example, the candidate correctional trajectory <NUM> includes intermediate targets <NUM>, <NUM>, and <NUM>. The candidate correctional trajectory <NUM> includes intermediate targets <NUM>, <NUM>, and <NUM>. In embodiments, such as the one shown, where the candidate correctional trajectory passes through multiple intermediate targets, the candidate correctional trajectory may be made up of multiple segments such as the illustrated segment <NUM>.

The user may also specify additional intermediate targets at the same hierarchical level. Although not illustrated, it will be appreciated that a user could specify an intermediate target '<NUM>' at the same hierarchical level as intermediate target <NUM>. In such an embodiment, both intermediate targets <NUM> and <NUM> are children of the current position <NUM>. The computing system may create candidate correctional trajectories for each of the one or more additional intermediate targets at the same hierarchical level.

As noted above, <FIG> illustrates that intermediate target <NUM> has child intermediate targets <NUM> and <NUM>. Child intermediate target <NUM> itself has a child <NUM>. <NUM>, and child intermediate target <NUM> has a child <NUM>. The computing system may be configured to generate candidate correctional trajectories for each of the one or more additional child intermediate targets set by the user. In <FIG>, this results in candidate correctional trajectory <NUM> and <NUM> respectively.

In one embodiment, the computing system requires that the user respect one or more of the target locations <NUM> as specified in the well plan. In such an embodiment, the computing system would not, for example, allow the user to create a candidate correctional trajectory that does not reach the target location <NUM>. The computing system may not require that the user set intermediate targets all the way to the target locations <NUM> specified in the well plan; it may, for example, allow the user to create a candidate correctional trajectory to get back on the planned trajectory <NUM> (as shown in <FIG>) provided the user is not bypassing any target locations <NUM> in instances where the well plan includes multiple target locations <NUM>.

In certain embodiments, the computing system validates each segment of the candidate correctional trajectory. The computing system may, for example, indicate whether the tools have sufficient motor yield to execute the segment. If the segment fails validation due to the inability of the tools to successfully construct that segment, the computing system may provide a notification and require the user to select a different intermediate location. The system may notify the user where no drilling parameters can be used to reach the intermediate target and thus is not achievable.

The computing system may also enforce one or more constraints specified in the well plan. The well plan may, for example, specify acceptable limits for tool operation, dog leg severity, or set other constraints. The computing system may automatically extract the constraints from the well plan. In such an embodiment, if the candidate correctional trajectory violates one or more constraints, the computing system may provide a notification and require the user to select a different intermediate location.

The computing system also presents one or more drilling parameters to reach the intermediate target in an editable format. In one embodiment, for multi-segment candidate correctional trajectories, the drilling parameters are presented for each segment. While, for simplicity, the discussion below assumes a single segment candidate correctional trajectory, the same approach may be applied to a multi-segment candidate correctional trajectory. For example, the computing system may present values for motor yield, dog leg severity (DLS), build rate, turn rate, and others for the segment <NUM>. The drilling parameters displayed may vary depending on tools and equipment in use; for example, the drilling parameters may vary depending on whether the directional drilling is being done using a motor or an RSS.

The computing system presents these drilling parameters for the candidate correctional trajectory to the user in an editable format. In response to receiving edits to the drilling parameters for the candidate correctional trajectory, the computing systemcalculates an updated position for the intermediate target using the edited drilling parameters and update the position for the user.

The computing system further provides the user with the option to select the candidate correctional trajectory and update the well plan using the selected candidate correctional trajectory.

This approach may allow the directional drilling team to more thoroughly explore different candidate trajectories to return the BHA to the planned trajectory <NUM> and evaluate the impact of the different options. As such, the approach can allow the directional drilling team to move ahead with greater confidence in their decisions and their ability to successfully construct the well.

<FIG> illustrates one embodiment of a graphical user interface (GUI) <NUM> for allowing the user to create candidate correctional trajectories. <FIG> illustrates a top section <NUM> that includes overview information for the well being drilled. It may, for example, include information about the status of the telemetry, the rig state, bit depth, hole depth, true vertical depth, and other values. In the embodiment shown in <FIG>, the bottom of the GUI <NUM> shows one or more key performance indicators (KPIs) for well construction.

The GUI may also present information about the next target specified in the well plan and the constraints <NUM>. <FIG> also illustrates multiple tabbed areas. One tab is "RT data" or real time data. The real time data tab may illustrate information about the real-time performance during well construction and include information relating to various drilling parameters, BHA position, and other data to assist the user in understanding the real time state of the well construction and the tools.

The active tab in <FIG> is entitled 'What-if' and presents the user with options to investigate options in well construction. The user in this instance has two candidate correctional trajectories, or 'projections' in the GUI, under consideration. Data for projection <NUM> is active in the display. In one embodiment, the computing system creates a new tab for each new candidate correctional trajectory under consideration.

In the depicted embodiment, the user is presented with a "projection from" option. The user may select the 'edit' option to indicate where the projection should begin. In one embodiment, the projection from menu option presents a list of previous surveys and the user can select a survey as a starting point. In instances where the drilling system collects continuous position data for the BHA the user may select the to use the continuous position information as the starting point.

The user, in the instance illustrated in <FIG>, has created one intermediate target for projection <NUM>. In response to the user creating the intermediate target, the computing system computes and display associated drilling parameters for the user. In the example shown, the GUI shows position data for the 'projection from' point and for the 'projection to' point. These different values are presented in an editable format such that the user can adjust one or more of the position data fields. As discussed above, this allows the user to refine the positions for either the starting point or the end point.

The GUI may also display one or more drilling parameters (referred to as projection parameters in the GUI). In the displayed embodiment, the projection parameter is the dog leg severity. The user may edit one or more of the projection parameters. In one embodiment, the user may select a button to trigger a recalculation of the projection results and location of the intermediate target based on the updated drilling parameters. In another embodiment, as shown, the user may select an 'auto update' option that automatically recalculates the projections in response to the user changing one or more of the position data and the drilling parameters.

The user may also have the option to set one or more additional constraints for the candidate correctional trajectory. In the example shown, the user has set constraint values for the TVD values. The user has set lower and upper limits. The results of the projection indicate that the projection satisfies the upper constraint limit for TVD (as indicated by the check mark) but fails to satisfy the lower limit (as indicated by the 'x' mark).

The GUI further provides the option to remove projections or add a new projection, thus creating a new segment in the candidate correctional trajectory as described above. The GUI may also show the different projections along with the planned trajectory (shown by the solid black line). The GUI may, in some embodiments, include markers indicating the positions from the positional data, whether by creating markers at each survey point, markers representing the continuous position data, or other.

The GUI may further, as shown, allow a user to zoom in on a particular section of the graphical representation of the planned trajectory and the one or more candidate correctional trajectories. While <FIG> illustrates a vertical section view, other views (such as a top view) may also be included as part of the display.

<FIG> are a flowchart of one embodiment of a method for updating a well plan with a correctional trajectory. The method begins with receiving <NUM> a well plan for a well to be directionally drilled. The well plan, as discussed above, will include one or more target locations.

The method includes receiving <NUM> positional data for a bottom hole assembly (BHA) during construction of the well and receiving <NUM>, from a user, an intermediate target.

While the above examples discuss the use of the intermediate target as part of a process for returning a BHA to the planned trajectory, in other embodiments the user is able to create the intermediate targets and perform the analysis described herein even when the BHA is on the planned trajectory. The directional drilling may, for example, anticipate potential problems in a section of the well and want to investigate alternative trajectories to avoid or mitigate the problems in that section. In such an embodiment, the candidate correctional trajectory may take the BHA off the planned trajectory for a certain distance and then return it to reach one or more target locations specified in the well plan.

The method involves creating <NUM> a candidate correctional trajectory that passes through the intermediate target specified by the user. This creation involves determining one or more drilling parameters to reach the intermediate target and presenting <NUM> the drilling parameters for the candidate correctional trajectory in editable format.

The method involves determining <NUM> whether there are edits to the drilling parameters. If yes, the method involves <NUM> calculating an updated position for the intermediate target using the edited drilling parameters and displaying the updated position to the user.

If no, the method involves determining <NUM> if there are additional intermediate targets. If yet, the steps from <NUM> are repeated until all additional intermediate targets have been included. Once all additional intermediate targets are considered, the method involves determining <NUM> whether there are child intermediate targets. If no, the method involves providing the user with an option to select the candidate correctional trajectory and receiving <NUM> the user's selection. The method ends with updating <NUM> the well plan using the selected candidate correctional trajectory.

As shown in <FIG>, if there are child intermediate targets, the method may involve calculating <NUM> a candidate correctional trajectory from the intermediate target to the child intermediate target and presenting <NUM> the drilling parameters for the candidate correctional trajectory from the intermediate target to the child intermediate target (e.g., a segment) in editable format. The method determines <NUM> whether there are edits to the drilling parameters. If so, the method includes calculating an updated position for the child intermediate target using the edited drilling parameters. The method may involve determining <NUM> whether there are additional child intermediate targets. If so, the process may repeat at <NUM> for the child intermediate targets until all additional child intermediate targets are accounted for and the method continues at <NUM>. While the above method make reference to one level of child intermediate targets, the approach may be extended to any number of additional hierarchical levels of intermediate targets.

As noted above, in certain embodiments the method may involve determining a current position of the BHA using the BHA position data, comparing the current position of the BHA to the expected position of the BHA as determined from the well plan, and determining whether the current position of the BHA is off the planned trajectory by a threshold amount. In certain embodiments, the method may automatically creating a generated correctional trajectory to move the BHA from the current position to the planned trajectory and presenting the generated correctional trajectory to the user.

The method may also include notifying the user if the computing system cannot identify drilling parameters that can be used to reach the intermediate point. In certain embodiments, the method may also require that the selected candidate correctional trajectory pass through each target location specified in the well plan.

The embodiments disclosed in this disclosure are to help explain the concepts described herein. This description is not exhaustive and does not limit the claims to the precise embodiments disclosed. Modifications and variations from the exact embodiments in this disclosure may still be within the scope of the claims.

Claim 1:
A method for updating a well plan for a directional well, the method comprising:
(a) receiving (<NUM>) a well plan for a well to be directionally drilled, the well plan including one or more target locations (<NUM>);
(b) receiving (<NUM>) positional data for a bottom hole assembly (BHA) during construction of the well;
(c) receiving (<NUM>), from a user, an intermediate target;
(d) creating (<NUM>) a candidate correctional trajectory (<NUM>) that passes through the intermediate target specified by the user, the candidate correctional trajectory further comprising one or more drilling parameters to reach the intermediate target;
(e) presenting (<NUM>) the one or more drilling parameters for the candidate correctional trajectory to the user in editable format;
(f) in response to receiving (<NUM>) one or more edits to the one or more drilling parameters for the candidate correctional trajectory (<NUM>), calculating (<NUM>) an updated position for the intermediate target using the edited drilling parameters and displaying the updated position to the user;
(g) providing (<NUM>) the user an option to select the candidate correctional trajectory; and
(h) updating (<NUM>) the well plan using the selected candidate correctional trajectory.