Patent Description:
<CIT> discloses a system and method for remotely controlled surface steerable drilling. <CIT> discloses methods and systems for drilling. <CIT> discloses drilling speed and depth computation for downhole tools. <CIT> discloses a system and method for remotely controlled surface steerable drilling. <CIT> discloses a surface steerable drilling system for use with a rotary steerable system <CIT> and <CIT> disclose methods and steering assemblies for drilling a borehole in an earth formation.

According to one aspect the present invention provides a system for controlling a trajectory of a borehole as claimed in claim <NUM>. According to another aspect the present invention provides a method for controlling a trajectory of a borehole as claimed in claim <NUM>.

A description of one or more embodiments of the disclosed apparatuses and methods are presented herein by way of illustration and example and are not intended to be limitations. Reference will be made to the appended to the figures.

Disclosed are apparatus and method for drilling a borehole into the earth. The method, which is implemented by the apparatus described herein or other controller, computer, and/or processor, provides a control approach that can be used to control a borehole trajectory that may be characterized, for example, by depth, drilled distance, inclination, azimuth, build-up-rate, distance to a formation boundary, distance to an object such as another borehole, a geologic object, a downhole installation, or any other borehole trajectory related parameter. As used herein, the term "depth" may be considered to be inclusive of data indicative of depth, such as "drilled distance" (also known as "measured depth"), true vertical depth, true stratigraphical depth in order to account for deviated or horizontal boreholes, or any other depth related data including depth data that is corrected for depth measurement influencing effects such as stretching/squeezing because of gravity effects, temperature effects, pressure difference effects, etc..

Apparatus for drilling operations related to this disclosure are now discussed. <FIG> shows a schematic diagram of a drilling system <NUM> that includes a drill string <NUM> having a drilling assembly <NUM>, that may include a bottom hole assembly (BHA), conveyed in a borehole <NUM> penetrating an earth formation <NUM>. The drilling system <NUM> includes a conventional derrick <NUM> erected on a floor <NUM> that supports a rotary table <NUM> that is rotated by a prime mover, such as an electric motor (not shown), at a desired rotational speed. The drill string <NUM> includes a drilling tubular <NUM>, such as a drill pipe, extending downward from the rotary table <NUM> into the borehole <NUM>. A disintegrating device <NUM> (e.g., a drill bit), attached to the end of the drilling assembly <NUM>, disintegrates the geological formations to drill the borehole <NUM>. Various types of disintegrating devices can be used. While the present disclosure is made with reference to rotary drilling utilizing a rotary drill bit, other drilling types such as electric pulse drilling, jet drilling, and/or percussion drilling may be utilized as well. The drill string <NUM> is coupled to a drawworks <NUM> via a kelly joint <NUM>, swivel <NUM> and line <NUM>, e.g., through a pulley and/or pulley system. During the drilling operations, the drawworks <NUM> is operated to control the weight on bit, which affects the rate of penetration (ROP). The operation of the drawworks <NUM> is well known in the art and is thus not described in detail herein.

During drilling operations a suitable drilling fluid <NUM> (also referred to as the "mud") from a source or mud pit <NUM> is circulated under pressure through the drill string <NUM> by a mud pump <NUM>. The drilling fluid <NUM> passes into the drill string <NUM> via a desurger and fluid control valve <NUM>, fluid line <NUM>, and the kelly joint <NUM>. The drilling fluid <NUM> is discharged at the borehole bottom <NUM> through an opening in the disintegrating device <NUM>. The drilling fluid <NUM> circulates uphole through the annular space <NUM> between the drill string <NUM> and the borehole <NUM> and returns to the mud pit <NUM> via a return line <NUM>. A sensor S1 in the line <NUM> provides information about the fluid flow rate. The flow rate can be controlled by a valve located in or near the pump <NUM> and/or the desurger and fluid control valve <NUM>, or otherwise located within line <NUM>. A surface torque sensor S2 and a sensor S3 associated with the drill string <NUM> respectively provide information about the torque and the rotational speed of the drill string. Additionally, one or more sensors (not shown) associated with line <NUM> are used to provide the hook load of the drill string <NUM> and about other desired parameters relating to the drilling of the wellbore <NUM>. The system may further include one or more downhole sensors <NUM> located on the drill string <NUM> and/or the drilling assembly <NUM>. The downhole sensors <NUM> can include one or more sensors configured to sense, measure, and/or detect, for example, a position, orientation, inclination, and/or azimuth of the sensor(s) and/or the BHA or other downhole component. Some or additional sensors may be configured to detect and/or measure formation properties and/or mud properties.

In some applications the disintegrating device <NUM> is rotated by only rotating the drill pipe <NUM>. However, in other applications, a drilling motor <NUM> (mud motor) disposed in the drilling assembly <NUM> is used to rotate the disintegrating device <NUM> and/or to superimpose or supplement the rotation of the drill string <NUM>. In either case, the rate of penetration (ROP) of the disintegrating device <NUM> into the borehole <NUM> for a given formation and a drilling assembly largely depends upon the weight on bit and the disintegrating device rotational speed. In one aspect of the embodiment of <FIG>, the mud motor <NUM> is coupled to the disintegrating device <NUM> via a drive shaft (not shown) disposed in a bearing assembly <NUM>. The mud motor <NUM> rotates the disintegrating device <NUM> when the drilling fluid <NUM> passes through the mud motor <NUM> under pressure. The bearing assembly <NUM> supports the radial and axial forces of the disintegrating device <NUM>, the downthrust of the drilling motor and the reactive upward loading from the applied weight on bit. One or more stabilizers <NUM> coupled to the bearing assembly <NUM> and other suitable locations act as centralizers for the lowermost portion of the mud motor assembly and other such suitable locations.

A surface control unit <NUM> receives signals from the downhole sensors <NUM> and devices, for instance, via a sensor <NUM> placed in the fluid line <NUM> (in case of a mud pulse telemetry) or elsewhere for other types of telemetry such as wired pipe telemetry, acoustic telemetry, or electromagnetic telemetry, as well as from sensors S1, S2, S3, hook load sensors and any other sensors used in the system and processes such signals according to programmed instructions provided to the surface control unit <NUM>. The surface control unit may process hook position data, hook load data, and/or other data such as weight on bit to determine, derive, or correct drilled distance, ROP, etc. The surface control unit <NUM> displays desired drilling parameters and other information on a display/monitor <NUM> for use by an operator at the rig site to control the drilling operations. The surface control unit <NUM> contains a computer, memory for storing data, computer programs, models and algorithms accessible to a processor in the computer, a recorder, such as tape unit for recording data and other peripherals. The surface control unit <NUM> also may include simulation models for use by the computer to processes data according to programmed instructions. The control unit responds to user commands entered through a suitable device, such as a keyboard. The control unit <NUM> is adapted to activate alarms <NUM> when certain unsafe or undesirable operating conditions occur.

The drilling assembly <NUM> also contains other sensors and devices or tools for providing a variety of measurements relating to the formation surrounding the borehole and for drilling the wellbore <NUM> along a desired path. Such devices may include a device for measuring the formation resistivity near and/or in front of the disintegrating device <NUM>, a gamma ray device for measuring the formation gamma ray intensity and devices for determining rotation speed (rpm), inclination, azimuth, ROP, and/or position of the drill string. A formation resistivity tool <NUM>, made according an embodiment described herein may be coupled at any suitable location, including above a lower kick-off subassembly <NUM>, for estimating or determining the resistivity of the formation near or in front of the disintegrating device <NUM> or at other suitable locations. An inclinometer <NUM> and a gamma ray device <NUM> may be suitably placed for respectively determining the inclination of the drilling assembly <NUM> and/or BHA and the formation gamma ray intensity. Any suitable inclinometer and gamma ray device may be utilized. In addition, an azimuth device (not shown), such as a magnetometer or a gyroscopic device, may be utilized to determine the drill string azimuth. Such devices are known in the art and therefore are not described in detail herein. In the above-described exemplary configuration, the mud motor <NUM> transfers power to the disintegrating device <NUM> via a hollow shaft that also enables the drilling fluid to pass from the mud motor <NUM> to the disintegrating device <NUM>. In an alternative embodiment of the drill string <NUM>, the mud motor <NUM> may be coupled below the resistivity measuring device <NUM> or at any other suitable place.

Still referring to <FIG>, other logging-while-drilling (LWD) devices (generally denoted herein by numeral <NUM>), such as devices for measuring formation porosity, permeability, density, rock properties, fluid properties, etc. may be placed at suitable locations in the drilling assembly <NUM> for providing information useful for evaluating the subsurface formations along borehole <NUM>. Such devices may include, but are not limited to, acoustic tools, nuclear tools, nuclear magnetic resonance tools and formation testing and sampling tools.

The above-noted devices transmit data to a downhole telemetry system <NUM>, which in turn transmits the received data uphole to the surface control unit <NUM>. The downhole telemetry system <NUM> also receives signals and data from the surface control unit <NUM> and transmits such received signals and data to the appropriate downhole devices (also known as downlink). In one aspect, a mud pulse telemetry system may be used to communicate data between the downhole sensors <NUM> and devices and the surface equipment during drilling operations. A transducer <NUM> placed in the mud supply line <NUM> detects the mud pulses responsive to the data transmitted by the downhole telemetry <NUM>. Transducer <NUM> generates electrical signals in response to the mud pressure variations and transmits such signals via a conductor <NUM> to the surface control unit <NUM>. In other aspects, any other suitable telemetry system may be used for two-way data communication between the surface and the drilling assembly <NUM>, including but not limited to, an acoustic telemetry system, an electro-magnetic telemetry system, a wired pipe, or combinations thereof. Repeaters may be used in conjunction with the telemetry system. The wired pipe may be made up by joining drill pipe sections, wherein each pipe section includes a data communication link that runs along the pipe. The data connection between the pipe sections may be made by any suitable method, including but not limited to, hard electrical or optical connections, induction, capacitive or resonant coupling methods. In case a coiled-tubing is used as the drill pipe <NUM>, the data communication link may be run along a side of the coiled-tubing.

The drilling system described thus far relates to those drilling systems that utilize a drill pipe to convey the drilling assembly <NUM> into the borehole <NUM>, wherein the weight on bit is controlled from the surface, typically by controlling the operation of the drawworks. However, a large number of the current drilling systems, especially for drilling highly deviated and horizontal wellbores, utilize coiled-tubing for conveying the drilling assembly downhole. In such application a thruster is sometimes deployed in the drill string to provide the desired force on the disintegrating device. Also, when coiled-tubing is utilized, the tubing is not rotated by a rotary table but instead it is injected into the wellbore by a suitable injector while the downhole motor, such as mud motor <NUM>, rotates the disintegrating device <NUM>. For offshore drilling, an offshore rig or a vessel is used to support the drilling equipment, including the drill string.

Still referring to <FIG>, a resistivity tool <NUM> may be provided that includes, for example, a plurality of antennas including, for example, transmitters 66a or 66b or and receivers 68a or 68b. Resistivity can be one formation property that is of interest in making drilling decisions. Those of skill in the art will appreciate that other formation property tools can be employed with or in place of the resistivity tool <NUM>.

As noted above, the drilling fluid <NUM> is pumped by a drilling fluid pump <NUM> and a flow rate of the drilling fluid is controlled by a desurger and drilling fluid control valve <NUM>. The drilling fluid pump <NUM> and flow control valve <NUM> are controlled by a drilling parameter controller <NUM> and/or the surface control unit <NUM> to maintain a suitable pressure and flow rate to prevent the borehole <NUM> from collapsing. The term "drilling fluid" is intended to be inclusive of all types of drilling fluids known in the art including, but not limited to, oilbased mud, water-based mud, foam, gas, and air. The drilling parameter controller <NUM> is configured to control, such as by feedback control for example, parameters of drilling equipment used to drill the borehole <NUM>.

One or more surface sensors (e.g., S1, S2, S3, <NUM>) or downhole sensors <NUM> (within drilling assembly <NUM> and/or along drill string <NUM>) may be used to provide feedback signals to the drilling parameter controller <NUM> for feedback control of drilling equipment. Non-limiting embodiments of drilling parameters include weight-on-bit, hook load, torque, drill bit rotational speed (e.g., rpm), rate-of-penetration (ROP), steering forces, depth, hook position, drill bit position, drilling direction, azimuth, inclination, tool face of the drilling assembly, pressure, mud flow rate, and formation evaluation measurements as described below. Control references, also known as set points, which may include set points related to a trajectory plan, can be transmitted to the drilling parameter controller <NUM> by the control unit <NUM> (e.g., a computer processing system).

In an alternative configuration, the drilling parameter controller <NUM> may utilize, include, comprise, or be part of the control unit <NUM>. The drilling parameter controller <NUM> can be, in some embodiments, installed downhole, for instance in drilling assembly <NUM>. The drilling parameter controller <NUM> can include one or more controlling elements (not shown) configured to deal with various components, features, and/or variables of the controlling aspects and which can be installed downhole or on surface or both. One or more stabilizers (not shown) may be disposed at various locations on the drill tubular, for instance at one or more distances Li (i = <NUM>, <NUM>, <NUM>. ) from the disintegrating device <NUM>.

As noted, the drilling assembly <NUM> and/or drill string <NUM> includes one or more downhole sensors <NUM> configured for sensing one or more downhole properties or parameters related to the earth formation <NUM>, the borehole <NUM>, the drilling fluid <NUM>, the drill string <NUM>, the drilling assembly <NUM>, etc. Parameters associated with the drilling assembly <NUM> that may be sensed and/or monitored can include, position of the drilling assembly <NUM>, orientation of the drilling assembly <NUM>, inclination of the drilling assembly <NUM>, tool face of the drilling assembly <NUM>, and/or azimuth of the drilling assembly <NUM>. Sensor data can be transmitted to the surface by the telemetry system <NUM> for processing by the control unit <NUM>.

Data acquisition by the downhole sensor(s) <NUM> while drilling the borehole <NUM> may be referred to as measurement-while-drilling (MWD) or logging-while-drilling (LWD). Sensed data can be correlated to a depth or a time at which the data was obtained to provide a depth-based or a time-based log. One example for a downhole sensor <NUM> is a formation evaluation sensor which can be a sensor configured to sense gamma-ray radiation. The gamma-ray radiation may be natural or may result from neutron bombardment of the formation, such as by a pulsed neutron generator, a radioactive source, or any other suitable neutron source known in the art. In other embodiments or in combination therewith, the downhole sensor(s) <NUM> can include sensors configured to sense resistivity, neutron radiation, acoustic energy, electromagnetic energy, electric energy, magnetic energy, nuclear magnetic resonance properties, chemical properties, formation porosity, formation density, formation permeability, fluid density, fluid viscosity, temperature, pressure, magnetic fields, force, acceleration, and/or gravity. The downhole sensor(s) <NUM> can comprise active or passive sensing elements. The downhole sensors <NUM> can operate as a part of a sensor system (e.g., as part of drilling assembly <NUM>) comprising transmitting and receiving elements. The downhole sensor(s) <NUM> may provide sensed measurements or data that is measured system output to the drilling parameter controller <NUM> for feedback control purposes.

The drilling assembly <NUM>, as shown, includes a steering system <NUM>. The steering system <NUM> is configured to steer the disintegrating device <NUM> in order to control orientation of the drilling assembly <NUM> in order to allow drilling the borehole <NUM> according to a selected path or geometry (for instance, by following a planned geometric path or by keeping a distance to an object). The steering system <NUM> can control, for example, inclination, azimuth, and/or tool face of the drilling assembly <NUM>. Further, the steering system <NUM> controls the drilling assembly <NUM> and/or the disintegrating device <NUM> to follow a planned geometric path or by controlling the drilling assembly <NUM> and/or BHA and drill string <NUM> to keep a desired distance to or from an object in the earth formation <NUM>.

For steering the drilling assembly <NUM> or disintegrating device <NUM>, the steering system <NUM> includes one or more actuators that are configured to convert a controller output from the drilling parameter controller <NUM> into a motion that can alter the path being drilled by the disintegrating device <NUM>. For example in a rotary steering system (RSS), an actuator can be a piston that moves a pad for providing a force exerted against a borehole wall thus steering the drilling assembly <NUM> and the disintegrating device <NUM>. In an alternative embodiment, steering the drilling assembly <NUM> can be controlled using bent downhole motors (not shown) where behavior can be changed by controlling the motor bent through rotating or non-rotating (i.e., sliding) the drill string <NUM>. Bent drilling motors can be used with a fixed bend that cannot be varied during normal operation or with a variable bend that, for example, can be varied based on a controller output of the drilling parameter controller <NUM>. In embodiments with a variable bend, actuators can be included in the bent downhole motor that are configured to create or vary the bend, thereby affecting the steering behavior of the steering system.

Accordingly, the term "steering system" is to be construed as including those components both downhole and/or at the surface (e.g., rotary table <NUM> and/or drilling fluid pump <NUM>) that operate in order to control a trajectory or orientation of the drill string <NUM> and/or the disintegrating device <NUM> for drilling the borehole <NUM>. It can be appreciated that the output of the control unit <NUM> and/or the drilling parameter controller <NUM> can be generated within the steering system <NUM> and does not necessarily need to be received from a source external to the steering system <NUM>. Accordingly, the term "controller output" is to be construed as including controller outputs that are received from a source external to the steering system <NUM> and/or generated internal to the steering system <NUM>.

In order to provide controller outputs (for example, a control signal or a system input) to the steering system <NUM> for controlling the trajectory or orientation of the disintegrating device <NUM>, the drilling parameter controller <NUM> is configured to implement a trajectory control algorithm, discussed below. Operation of the trajectory control algorithm employs a processor such as in the control unit <NUM>, the drilling parameter controller <NUM>, and/or other processing system.

In various embodiments, the drilling parameter controller <NUM> can be disposed downhole, at the surface, and/or functions can be split between a surface processor and a downhole processor. Steering commands or other controller outputs can be transmitted from the drilling parameter controller <NUM> to the steering system <NUM> by telemetry. In addition, other information of interest (e.g., rate-of-penetration or position, depth, drilled distance, orientation, and/other sensor measurements) can be transmitted using telemetry. Telemetry in one or more embodiments may include mud pulse telemetry, acoustic telemetry, electromagnetic telemetry, telemetry by rpm variations, and/or wired pipe telemetry. Downhole electronics <NUM> may process data downhole and/or act as an interface with the telemetry. In other embodiments, the downhole electronics within the drilling assembly <NUM> can be configured to implement the trajectory control algorithm or portions thereof. In such embodiments, the control unit <NUM> can transmit a desired trajectory (i.e., trajectory plan) or parts of the trajectory if that is all that is needed, to the drilling assembly <NUM>, steering system <NUM>, and/or drilling parameter controller <NUM>. In some embodiments, if the trajectory is described as a parameterized curve, only the parameters can be transmitted. In non-limiting embodiments, the trajectory can be in absolute coordinates (such as north-east-down) or the trajectory can be depth sequence for the orientation (such as inclination, azimuth, tool face), or a distance to an object.

For controlling a system, for instance the drilling system <NUM> to create a borehole trajectory, a mathematical description of the drilling system <NUM> can be utilized to estimate a potential system output in response to a system input that may comprise a control output. As a non-limiting example, a mathematical description can be one or more system equations. As used herein, the term "system equation" includes a set of system equations comprising more than one single equation. Those of skill in the art will appreciate that there are many types of system equations, and the present disclosure is not limited to any particular system equation and/or set of system equations. A non-limiting example are system equations that are differential equations of the order n. Typical conventional dynamic systems, known for example from technical processes, can be described with a first order differential equation with respect to time t: <MAT> where y(t) denotes a system output, f(y(t),u(t),t) is a function describing the system behavior and u(t) is the system input that causes the system output (bold type denoting a vector). The system equation can also be stated in discrete time-based notation for implementation into and solution by a digital processor: <MAT> with a discretization time interval Ts and time tk=k Ts, k=<NUM>,<NUM>,<NUM>,. The discretization time interval Ts can be a fixed value or may be variable. The length or the boundaries of the discretization time interval Ts can be predefined. Those skill in the art will appreciated that there are other methods of implementation into a digital processor known in the art, including, but not limited to, a finite element method that may be utilized accordingly.

Both of the above system equations (Eqs. (<NUM>)-(<NUM>)) describe a rate of change with respect to time. An example is a velocity response of a car when stepping on an accelerator pedal. Because the time response to a given input is known for these systems, discrete time-based control algorithms can be designed and parameterized using standard methods as known in the art. However, there are other systems for which the reaction to a control output cannot be described by a unique function with respect to time. For example, in the drilling system <NUM>, the system output (that is, the response or the reaction) of the drilling system <NUM> in response to a steering force applied by an actuator and/or pad of the drilling assembly <NUM> to a borehole wall depends significantly on a rate of penetration (ROP) of the drilling system <NUM>. For instance, if the ROP of disintegrating device <NUM> is zero during a particular time interval Δt, that is if the drilling assembly <NUM> does not move in an axial direction along the borehole <NUM> during the time interval Δt, a steering force applied to the borehole wall by a pad of the drilling assembly <NUM> will not cause any change in the drilling direction. However, in contrast, if the ROP of the drilling system <NUM> is relatively high, the effect of that same steering force might lead to a significant change of the drilling direction during the time interval Δt.

As explained above, the output of the drilling system <NUM> in response to a steering control output is a function of spatial position rather than a function of time. Accordingly, the reference for the path or geometry of the borehole <NUM> being drilled or planned (also known as a "well plan") describes the path or geometry with respect to its spatial position and/or orientation. The spatial position and/or orientation can be described with respect to depth or drilled distance, rather than with respect to time.

As described above, a process for controlling a drilling process can be implemented using the control unit <NUM> and/or the drilling parameter controller <NUM>. <FIG> and <FIG> show schematic illustrations of control systems in accordance with the present disclosure. <FIG> and <FIG> can be read and described in representing a physical implementation of a control system. Alternatively, <FIG> and <FIG> and their associated description can be understood as a framework of modeling packages to simulate the output of the physical implementations of a control system and/or parts of a control system. The simulations by these modeling packages can then be used to adjust a parameter set of a corresponding physical implementation of the control system and related (e.g., discrete) control algorithms.

<FIG> shows an example schematic illustration of a process that can be implemented on one of the control unit <NUM> and/or the drilling parameter controller <NUM>. As shown, a reference value also referred to as a target value is input at the left side of <FIG>. This reference value can be compared to a measured output obtained from sensors (e.g., sensors S1, S2, S3, <NUM>, <NUM>) resulting in a measured error that is input into the control device (e.g., the control unit <NUM> and/or the drilling parameter controller <NUM>). The control device (e.g., <NUM>, <NUM>) generates a system input that is provided to the system (e.g., drilling system <NUM>) which is then output as a drilling operation. The system in turn can comprise further control loops, such as shown and discussed herein. During the drilling operation, sensors (e.g., sensors S1, S2, S3, <NUM>, <NUM>) can monitor aspects of the drilling system <NUM> and thus generate a measured output that is provided in a feedback loop to the controller (e.g., <NUM>, <NUM>), and thus the system input and system output can be actively adjusted based on the measured features monitored by the sensors (e.g., sensors S1, S2, S3, <NUM>, <NUM>) to provide an accurate and efficient drilling operation.

Turning now to <FIG>, an example of the geometry of a well plan is schematically shown. The geometry of the borehole <NUM> is described by the vector b(s) where s denotes the drilled distance (also known as measured depth) along the trajectory as illustrated in <FIG> (where i<NUM>, i<NUM>, and i<NUM> are three orthogonal directions). As a non-limiting example, a system equation that describes the vector b(s) may be a differential equation of the order n. For example, if n = <NUM>, the differential equation db(s)/ds describing the borehole geometry vector b(s) may be stated as follows: <MAT> where F( ) is a function describing the output of the drilling system <NUM> (which may be substantially similar to drilling system <NUM> of <FIG>) in response to a control output, i.e., the variation of the vector b in dependence of the drilled distance. u(s) is a system input (e.g., the steering forces applied by a steering system) that may comprise a control output and d(s)/ds is the tangent vector of the trajectory, e.g., at the disintegrating device (e.g., drill bit) describing the drilling direction.

It can be seen that in this case the system equation (Eq. (<NUM>)) is time independent. The system equation Eq. <NUM> depends only on a drilled distance s along the trajectory. Downhole sensors <NUM> and/or surface sensors S1, S2, S3, <NUM> can be configured to monitor parameters indicative of the drilling direction db(s)/ds such as, but not limited to, inclination, inclination rate (also known as buildup rate), azimuth, azimuth rate, dogleg severity, depth, drilled distance, ROP, distance to an object, or any combination of these. One or more of the sensed parameters indicative of (s)/ds may be compared with a reference (also known as set point) that may be part of a well plan. Such comparison can be made to determine a measurement error (cf. <FIG>) to adjust the control output of the drilling parameter controller based on the depth-based system equation (e.g., feedback loop shown in <FIG>). Such measurements and comparisons can be made to minimize the measurement error as a drilled distance increases. When, for example, a specific steering force is applied by the steering system of the drilling system <NUM>, an inclination response is a function of depth or drilled distance rather than a function of time. The differential equation (Eq. (<NUM>)) describing the current drilling direction is a delay differential equation because the drilling direction is also influenced by the position of stabilizers (not shown) on the BHA and drill string. The distances from the disintegrating device to the stabilizers are denoted with L<NUM>. LN in Eq. (<NUM>).

The discretized system equation corresponding to the delay differential equation for implementation into and solution by a digital processor can be stated as follows: <MAT> with drilled distance sk = kDs, k = <NUM>,<NUM>,<NUM>,. and discretization drilled distance interval Ds. The discretization drilled distance interval Ds can be a fixed value or can be variable. The length or the boundaries of the discretization drilled distance interval Ds, in some embodiments, can be predefined. In one or more embodiments, the selected drilled distance interval Ds can be decreased in areas or volumes of interest in a formation to provide a more accurate trajectory. Those of skill in the art will appreciate that there may be other methods of implementation into a digital processor, such as a finite element method.

It can be appreciated that discrete depth-based control is one non-limiting embodiment of what may be described generally as "depth-based control. " In another non-limiting embodiment, depth-based control may include continuous depth-based control where depth or drilled distance is continuous or not discretized. Common drilling parameter controllers (e.g., <NUM> in <FIG>) are configured to employ discrete time-based control algorithms that calculate new controller outputs every sampling time interval. The sampling time interval can be identical to or different from a discretization time interval. Contrary to drilling parameter controllers utilizing a discrete time-based system equation, drilling parameter controllers utilizing a discrete depth-based system equation calculate new controller outputs every sampling drilled distance interval, at predetermined drilled distances, or at predetermined drilled distance intervals. The sampling drilled distance interval can be identical to or different from the discrete drilled distance interval. The predetermined drilled distances or drilled distance intervals at which the drilling parameter controller utilizing a discrete depth-based system equation to calculate new controller outputs might be identical to or different from the predetermined drilled distances or drilled distance intervals used to define the discretization drilled distance interval Ds.

Those of skill in the art will appreciate that the depth-based system equation (Eq. (<NUM>)) could be transformed into a time-based system equation. A depth-to-time transformation can be accomplished using the following relationship:
<MAT>
where ROP<IMG> is rate-of-penetration of the disintegrating device into the earth. From the transformation of Eq. (<NUM>), it is seen that if ROP is known and constant over time, s and t are proportional and the time-based system equation (Eq. (<NUM>)) can be transferred into a depth-based system equation (Eq. (<NUM>)) and vice versa. In drilling systems, however, ROP is usually highly variable and cannot be predicted because it depends on many unknown factors such as the geology being drilled through and human input from a drilling operator on the surface.

For this reason, the system equation of the drilling system with respect to drilled distance (Eq. (<NUM>)) can be well known. However, the system equation of the drilling system with respect to time (Eq. (<NUM>)) may lack necessary information regarding the time dependency of ROP and is therefore unknown or known only within a relatively broad range reflecting the range of ROP that the drilling system might experience. Accordingly, the lack of information of the time dependency of the ROP can lead to relatively high inaccuracies when predicting the output of the drilling system in response to a control output of the drilling parameter controller. Consequently, by utilizing a time-based system equation (e.g., Eq. (<NUM>)), the relatively high inaccuracy of the system equation can lead to improperly calculated controller outputs which in turn can lead to overshoots or undershoots of the output of the drilling system that is to be controlled. Repeated improper calculated controller outputs can lead to oscillations of the drilling system that are highly undesired. For example, such oscillations can cause lower overall ROP, deviations from a well plan, higher wear, and generally higher cost. Oscillating well trajectories can also impede the installation of downhole equipment after the borehole is drilled, including, but not limited to, casings, liners, production equipment, etc..

When setting up or designing a time-based control of a drilling system by a drilling parameter controller, in view of the unknown and/or variable ROP, it is possible to make assumptions with respect to the ROP of the drilling system during operation. For instance, one possible assumption is that the ROP will be constant during the operation and set up the controlling parameter accordingly. In that case, the system equation is accurate and valid for only one particular (assumed) ROP. Thus, a time-based control algorithm based on a system equation is only optimal for a particular (assumed) ROP. Drilling with higher or lower ROP can result in an unstable system or in a suboptimal control performance using control systems utilizing time-based system equations.

For example, if several layers of different types of rock are being drilled, the ROP can vary due to the different characteristics of the different types of rock. In this type of situation the control may become unstable creating unwanted oscillations of the controlled system and/or deviations from the planned well trajectory. On the other hand, depth-based control in this type of situation is not dependent on ROP and can provide for stable drilling conditions. Describing the drilling system behavior as a unique function of depth or drilled distance allows common design methods for conventional control systems (e.g., Nyquist, Hurwitz criteria, Root-locus-plot, etc.) allowing much more accurate control results than if applied to a time-based system equation.

The technical effect of the unknown ROP on a system which is controlled based on a time-based system equation could be mitigated to some extent (although not eliminated), if the ROP could be measured instantaneously and the control output could be adjusted based on the measured ROP. However, measuring the downhole ROP of drilling systems can be difficult due to a high variability with respect to time, as noted above. In addition, the ROP of drilling systems is also not constant with respect to drilled distance. In particular, the ROP measured on surface might significantly differ from the ROP measured downhole. Such differences can arise from stretching or squeezing effects, temperature effects, pressure differences, and other factors. If telemetry is involved, the instantaneous determination of ROP can be impeded as the telemetry from downhole to surface and vice versa can be too slow for many telemetry systems such as mud pulse telemetry, acoustic telemetry, electromagnetic telemetry, etc. Further, such telemetry systems can be limited by amounts of data transferred (e.g., in the range of only tens of bits per second) and/or can be expensive.

Referring now to <FIG>, a schematic block diagram of a non-limiting embodiment of a depth-based control system is shown. The depth-based control system <NUM> of <FIG> implements a well plan <NUM> which can be input into a computer or other control device. Various aspects of the depth-based control system <NUM> can be implemented, for example, in one or both of the control unit <NUM> and/or the drilling parameter controller <NUM> of <FIG>. For example, a trajectory control unit <NUM> that can be part of a drilling parameter controller <NUM> is configured to provide controller outputs (e.g. control signals) to a BHA in a borehole in accordance with the well plan <NUM>. The well plan <NUM> can include information about the planned borehole as a function of drilled distance. The trajectory control unit <NUM> provides control outputs to an inclination/azimuth control unit <NUM> for inclination/azimuth control of the inclination and/or azimuth of the borehole being drilled.

The inclination/azimuth control unit <NUM> can receive inclination and/or azimuth feedback from components of a BHA that is performing a drilling operation. The inclination/azimuth control unit <NUM> outputs to an actuator control unit <NUM> which can be at the surface or downhole) for control of actuators <NUM> that are located downhole, e.g., as part of a BHA. The actuators <NUM> are configured to operate on one or more aspects of a BHA <NUM>, for controlling drilling operations. The BHA <NUM>, in some embodiments, may include a steering system (e.g., steering system <NUM> of <FIG>). The actuator control unit <NUM> can receive feedback control to ensure a desired position of the actuator <NUM> is achieved. In some embodiments, a surface top-drive can be used to control the orientation of a mud-motor and thus the trajectory for drilling the borehole, with similar control operations and components configured for such application. In some embodiments, the BHA <NUM> or other parts of the depth-based control system <NUM> can receive disturbances that may be difficult or impossible to control including and/or related but not limited to BHA design 312a, torque-on-bit, weight-on-bit 312b, and/or information related to a prior instance well path 312c.

The design and operational parameters of the BHA <NUM> determine the forces at the bit and bit orientation. Accordingly, the design and operational parameters of the BHA <NUM> may have an effect on the bit-formation interaction <NUM> that in turn may affect the output of the system such as one or more of the ROP and the drilling direction (i.e., inclination and azimuth). In addition, the bit-formation interaction <NUM> may be affected by disturbances that are difficult or impossible to control during drilling such as, but not limited to, bit properties 314a, formation properties 314b, and/or drilling constraints 314c (e.g., weight-on-bit, torque-on-bit, RPM, flow rate, mud, etc.). Changes in ROP <NUM> and/or the drilling direction will be added together or integrated over a particular depth interval, which is represented by box <NUM> in FIG. Adding together or integration of changes in ROP <NUM> and/or drilling direction will then lead to an altered position of a disintegrating device (e.g., drill bit; disintegrating device <NUM> at borehole end <NUM> in <FIG>). The altered position of the disintegrating device is then part of the system output <NUM> of the depth-based control system <NUM> that is in accordance with the well plan <NUM>.

The depth-based control system <NUM> is configured to execute a depth-based control algorithm by utilizing a depth-based system equation, as described above. The depth-based control algorithm, in some embodiments, can be executed every sampling drilled distance interval. That is, controller outputs are updated every time a sampling drilled distance interval is achieved using a depth-based system equation. The trajectory control unit <NUM> receives to this end information about the drilled distance, measured depth, or other depth-related data such as true vertical depth or true stratigraphical depth. This information may be received from a feedback loop as illustrated in <FIG> or form a separate data source (not shown in <FIG>) as further discussed and described below. In one or more embodiments, the selected sampling drilled distance interval is approximately one-half meter or one meter.

Non-limiting embodiments of a depth-based control algorithms implemented by the depth-based control system <NUM> include proportional control, proportional-integral control, and proportional-integral-derivative control. The depth-based control algorithms are configured to reduce measurement error (cf. <FIG>) measured by feedback over drilled distance by adjusting of a control variable that can be changed by movement of an actuator, for example. In one or more embodiments, multiple sub-controllers, such as the trajectory control unit <NUM> and/or the inclination/azimuth control unit <NUM> can be incorporated into one controller that performs the functions of the multiple sub-controllers.

Those of skill in the art will appreciate that other control designs (e.g. state space control) can be employed without departing from the scope of the present disclosure. Furthermore, the approach for depth-based control algorithms is independent of the type of the steering system (e.g., point-the-bit, push-the-bit, rotary steering system, bent motor, etc.).

Control systems that employ depth-based control algorithms as provided herein can include, for example, trajectory control systems (e.g., controlling a position of a well with respect to a given well plan) or direction control systems (e.g., controlling inclination or azimuth). There are different depth-based control algorithms that can be used (e.g., PID Control, Model Predictive Control, fuzzy control, etc.) and/or different control architectures that can be used (e.g., direct control architecture, subsidiary control architecture, etc.).

In direct control architectures, the output of a trajectory control unit is a target value for a steering unit actuator (e.g., the target forces for steering ribs or pads). In subsidiary control architectures (or secondary control architectures) an outer control loop for a trajectory control unit and an inner loop for a direction (inclination, azimuth) control unit are used. Additional, inner control loops are possible, e.g., a force control for steering pads. The output of an outer control loop can be a target value for the inner loop. For example, outputs of trajectory control unit <NUM> can be target inclination and target azimuth. The outputs of the inclination/azimuth control unit <NUM> are target forces where for example the output of the force controller may be target motor currents. In one or more embodiments, if subsidiary control with a depth-based trajectory control as an outer control loop is used, then the inner control loops may not necessarily need to be depth-based controls. For example, the inner control loop algorithms can be time-based. As such, a mix of depth-based and time-based controls and algorithms can be employed for the inner control loops.

Referring now to <FIG>, a block diagram of a non-limiting embodiment of a controller implementation using a formation evaluation sensor is illustrated. Control system <NUM> can include a flow process for controlling a drilling operation. The control system <NUM> includes a sensor <NUM>. The sensor <NUM> can be a formation sensor configured to detect or measure one or more characteristics of a formation <NUM>. In some non-limiting embodiments, the sensor <NUM> is a measurement-while-drilling (MWD) sensor such as a gamma sensor.

The sensor <NUM> provides a sensor signal <NUM> output that may be compared with a target value that may be part of and/or derived from a well plan <NUM> (e.g., the sensor signal <NUM> input to a comparison with a target value of the well plan to adjust the input of an inclination/azimuth control unit <NUM> described below). The target value of the well plan <NUM> and the sensor signal <NUM> from sensor <NUM> can be based on various formation characteristics, such as gamma-ray readings. In such a configuration, a formation characteristic control unit <NUM> can receive the target value or other input from the well plan <NUM> and the sensor signal <NUM>. As such, when the sensor <NUM> is a gamma-ray sensor, the sensor signal <NUM> represents a gamma-ray count rate. The formation characteristic control unit <NUM> can be configured to control the distance from a downhole feature (e.g., cap-rock) that emits gamma-rays. The automatic control can be achieved by controlling the direction of the borehole being drilled so that gamma-ray counts are at a constant value. To maintain a constant gamma-ray count, the formation characteristic control unit <NUM> can output control signals to an inclination/azimuth control unit <NUM> and/or an actuator control unit <NUM> that controls an actuator <NUM>. Accordingly, a drilling assembly <NUM> within the formation <NUM> can be controlled based on a formation characteristic and directional drilling in accordance with a well plan can be maintained.

Those of skill in the art will appreciate that other types of sensors can be used without departing from the scope of the present disclosure. For example, the sensor <NUM> of <FIG> can be an acoustic sensor, a magnetostatic sensor, an electromagnetic sensor, and/or other type of downhole sensor. Further, in some embodiments, multiple sensors of the same type or different types can be used to provide information and feedback for controlling drilling operations.

The well plan <NUM> of <FIG> may comprise one or more target values that are selected for the measurement being performed by the sensor <NUM> (e.g., target gamma-ray count value, slope, noise level, etc.). As noted above, multiple sensors can be employed in various embodiments of the present disclosure and the multiple sensors can be configured to measure different properties or parameters of the formation and/or BHA. For example, the sensor <NUM> can be configured to measure resistivity of a formation. As another example, a BHA can have a sensor for measuring gamma-rays and another sensor for measuring resistivity. In such configuration, the gamma-ray measurements can provide a distance to cap-rock while the resistivity measurement provides a distance to an oil-water contact. In some embodiments, the output of more than one sensor can be combined to a single control variable that may be used as a control variable in the formation characteristic control unit <NUM>.

Referring now to <FIG>, a block diagram of a non-limiting embodiment of a control system <NUM> employing a depth-based drilling trajectory control implementation on surface is illustrated. The embodiment shown in <FIG> is a distributed depth-based control system <NUM>, i.e., a portion of the control system <NUM> is located on the surface, indicated as to the left of the vertical dashed line <NUM>, and a portion of the control system <NUM> is located downhole, indicated as to the right of the vertical dashed line <NUM>. A well plan <NUM> can be input into a surface control unit <NUM> (e.g., similar to control unit <NUM> of <FIG>). The surface control unit <NUM> can be utilized to automatically, semi-automatically, or manually vary parameters of the drilling system via a rig control unit <NUM> and also be in communication with downhole components (e.g., the BHA and components thereof) through a downlink system <NUM>. The surface control unit <NUM> can receive surface or downhole information and/or data at a data processor <NUM>. Surface or downhole information or data may include depth of a reference location on the drilling assembly. Downhole data or information may be provided through telemetry <NUM> and/or other data communication means or mechanism. The data processor <NUM> can generate input data <NUM> by processing the downhole information and/or surface information (e.g., mud, ROP, survey information, depth, drilling direction, vibration, rpm, weight-on-bit, torque-on-bit). Information and/or data may comprise measured information and/or data or simulated information and/or data, etc. The input data <NUM> can be used to determine deviations or measurement errors from reference values (cf. <FIG>) that may be part of the well plan <NUM>.

The control output or measurement error (e.g., control signals from the surface control unit <NUM>) can be used to control downhole components including, but not limited to, an inclination/azimuth control unit <NUM> and/or an actuator control unit <NUM> that controls one or more actuators <NUM>. Controlling the control units <NUM>, <NUM> may include modifying control modes and/or parameterization of control algorithms implemented in the control unit <NUM> and/or control unit <NUM>. Further, the control output from the surface control unit <NUM> can be used to influence and/or control a BHA <NUM>, a bit-formation interaction <NUM>, and/or the adding or integration <NUM> over a particular depth interval (similar to that described above with respect to <FIG>). Further, similar feedback loops described and shown above can be utilized in the control system <NUM>. The control system <NUM> can implement changes at the surface (e.g., advice change to plan, advice to ream, advice to change bit and/or BHA design, etc.). Additionally, additional information and actions can be translated or transmitted from the surface, including, but not limited to, surface control of weight-on-bit, RPM, flow rates, mud properties, etc. that can be implemented through the rig control unit <NUM>. Similarly, the downlink <NUM> can be used to send control updates and/or changes to downhole components, including the BHA (e.g., changing active bit features, changes in control mode, controller, and/or parameterization, etc.).

An advantage of implementation of the distributed depth-based control system, as shown in <FIG>, is that all information required for depth-based trajectory control is available at the surface on conventional drilling systems or can be easily derived (e.g., reference trajectory, information about current position such as from a survey, depth, drilled distance, etc.). Furthermore, depth-based control on surface can make easier use of surface actuation (e.g., weight-on-bit, rotational speed, mud flow rate, etc.) in order to influence a drilling trajectory or change constraints such as, but not limited to, disturbances 312a, 312b, 312c, or drilling constraints 314c.

In the embodiment of <FIG>, the surface control unit <NUM> can receive drilling direction information from downhole components. For example, the drilling direction information can be obtained from the BHA <NUM> or other downhole components via telemetry <NUM> and/or from surface information such as survey information. In addition, the surface control unit <NUM> can receive the well plan <NUM>. Using this information, the surface control unit <NUM> can provide control outputs, drilling constraints, or disturbances (such as 312a, 312b, 312c in <FIG>) downhole via the downlink <NUM> and surface control signals to surface drilling equipment (e.g. rig control unit <NUM>) for controlling weight-on-bit, rotational speed, mud flow rate, mud properties, etc. The signals sent downhole can be configured to switch the BHA into a different operational mode, change downhole control algorithms, change control parameterization, etc. The signals sent downhole may also be configured to activate or influence active BHA devices (e.g., active bit, reamer, additional stabilizers, and/or other mechanical properties of the BHA which could be actuated) via downlink <NUM>. The surface control unit <NUM> may also be configured to provide advice to a user when a parameter does not meet or exceed a threshold value or, alternatively, exceeds a threshold value depending on the parameter. For example, if the ROP does not meet a selected value, the surface control unit <NUM> can issue a suggestion to change the disintegrating device or to change the BHA. Other advice may include a suggestion to change a drilling plan, to ream the borehole, or to change a previous borehole path. Alternatively, an automatic or semi-automatic ROP optimization process can be applied.

Referring now to <FIG>, a block diagram of a non-limiting embodiment of a control system <NUM> employing a depth-based control implementation downhole is illustrated. The embodiment in <FIG> is a distributed depth-based control system, i.e., a portion of the control system <NUM> is located on the surface, indicated as to the left of the vertical dashed line <NUM>, and a portion of the control system <NUM> is located downhole, indicated as to the right of the vertical dashed line <NUM>. The control system <NUM> includes a well plan <NUM> and a downhole control unit <NUM> (e.g., downhole electronics and/or a combination with surface and downhole electronics). The control system <NUM> further includes a rig control unit <NUM> and communication is enabled with downhole components (e.g., a BHA and components thereof) through a downlink system <NUM>. A data processor <NUM> located on the surface can receive information and/or data through telemetry <NUM> and/or other data communication means or mechanism. In particular, the data processor <NUM> can receive depth information or depth related information such as number and length of drilling tubulars and hook position. Such information allows the system to calculate drilled distance that is required to apply the depth-based control algorithm described above. The data processor <NUM> can generate further input data <NUM> by processing downhole information and/or surface information (e.g., mud properties, flow rate, ROP, survey information, drilling states, etc.). The input data can be measured data, simulated data, or both. The input data <NUM> can be used to update and/or otherwise modify the well plan <NUM>.

The downhole control unit <NUM> can be used to control downhole components including, but not limited to, an inclination/azimuth control unit <NUM> and/or an actuator control unit <NUM> that controls one or more actuators <NUM> in the BHA <NUM>. Further, the control signals from the downhole control unit <NUM> can be used to influence and/or control other parts of the BHA <NUM>, the bit-formation interaction <NUM>, and/or the adding/integration <NUM> over a particular depth interval (similar to that described above with respect to <FIG>). Further, similar feedback loops described and shown above can be utilized in the control system <NUM>. The control system <NUM> can implement changes at the surface (e.g., advice change to plan, advice to ream, advice to change bit and/or BHA design, etc. via data processor <NUM> or downlink system <NUM>). Additionally, additional information and actions can be translated or transmitted to the surface, including, but not limited to, surface control of weight-on-bit, RPM, flow rates, mud properties, etc. that can be implemented through the rig control unit <NUM>. Similarly, the downlink system <NUM> can be used to send control updates and/or changes to downhole components, including the BHA (e.g., changing active bit features, changes in control mode, controller scheme, and/or parameterization of the control system, etc.).

Depth-based downhole trajectory control as enabled in control system <NUM> employs information about ROP or a depth or drilled distance increment. These values are typically measured on surface in conventional rigs and can be transmitted downhole from the surface via downlink system <NUM>, telemetry <NUM> using wired drill pipe, mud pulse telemetry, acoustic telemetry, electromagnetic telemetry, rpm variations, etc. In some application, however, it may be possible to measure depth, drilled distance, or ROP downhole and convey such information directly or via data processor(s) to the control units <NUM>. Sensors and/or algorithms to determine depth and position related information such as drilled distance or drilling orientation are represented by element <NUM> in <FIG>. Information (e.g., change in rotational speed, mud flow rate, etc.) can be transmitted downhole every drilled depth increment (e.g., every drilled meter). In some embodiments, the rotational speed (rpm) or mud flow rate can be changed every drilled depth increment. With this concept, information can be sent to the downhole tool (e.g., BHA <NUM>, etc.) that a depth increment has been drilled. In some embodiments, for example when using an autodriller in constant ROP mode, the ROP typically stays constant over a long period of time and may be downlinked through downlink system <NUM> to the downhole control unit <NUM>. The downhole control unit <NUM>, in some embodiments, can be configured to evaluate a latest received ROP and switch control parameterizations as needed.

In embodiments such as shown with control system <NUM> in <FIG>, surface control does not necessarily need to be a classic control loop. The control system <NUM> can include surface control aspects that automate some or all trajectory drilling related tasks (e.g., taking surveys, sending downlinks, changing rig set points, etc.). Some control loops which require downhole measurements (e.g., inclination-, azimuth-, or actuator-control) may be easier to implement downhole. For this reason, the control system <NUM>, in some embodiments, can be a distributed control system in which some control functions are performed at the surface and other control functions are performed downhole, as shown in <FIG>. Further, control features such as reference variable splines, discussed below, allow distribution of trajectory control while minimizing a number of downlinks.

Referring to <FIG>, a block diagram of a control system <NUM> embodiment of a surface controller <NUM> implementation using one or more reference values (e.g., target inclination) is illustrated. A well plan <NUM> can be input to the surface control unit <NUM> which can output control output to be transmitted to various downhole components (e.g., BHA). The surface and downhole components are separated in <FIG> by vertical dashed line <NUM>. The downhole components can include, but are not limited to, an inclination/azimuth control unit <NUM>, an actuator control unit <NUM> that controls an actuator <NUM>, and/or a drilling assembly <NUM>. Those of skill in the art will appreciate that additional and/or other components and/or various feedback loops and/or other inputs can be employed without departing from the scope of the present disclosure.

In this non-limiting embodiment, information <NUM>, like a set of polynomial parameters, can be output from the surface control unit <NUM> and sent to a target value generator <NUM> (e.g., target values for a spline, a ramp, or any other parameterized curve). The target value generator <NUM> is used to generate target values employed as reference input for the control system <NUM> to have a depth or drilled distance-dependent reference value. System outputs are then referenced against the depth or drilled distance-dependent target or reference value (e.g., to minimize the difference between a controlled parameter and the target value). Advantageously, embodiments such as control system <NUM> enable, for example, features such as soft landing, complex well paths with a minimum number of downlinks, etc..

For example, as enabled by control system <NUM>, only the parameters of a reference trajectory need to be downlinked. That is, as shown in <FIG>, the surface control unit <NUM> can provide a parameterized curve, the parameter of which included information <NUM>, to the target value generator <NUM>. The target value generator <NUM> can thus provide one or more reference values to one or more of the various units downhole (e.g., units <NUM>, <NUM>, <NUM>, etc.).

In one or more embodiments, because a target-trajectory can be known in advance, a pre-control or pre-filter can be used as illustrated in <FIG>. The control system <NUM> is a subpart of a control system similar to those described above, and thus various features are omitted for simplicity. In control system <NUM> a control unit <NUM> (on surface or downhole) can provide control signals to one or more downhole tools and/or devices <NUM> (which may include a BHA including a steering unit, and/or other units as described herein or as known in the art). The control unit <NUM> can receive target values <NUM> as input, with the target values <NUM> being passed through a pre-filter <NUM> and/or a pre-control unit <NUM>. As shown, the downhole tools and/or devices <NUM> can be subject to disturbances <NUM>, as discussed above, and further can make measurements <NUM> which can be looped back into the control system <NUM> through a feedback loop.

Such a filter configuration (e.g., pre-filter <NUM>) can add a degree of freedom and allows optimization of a disturbance transfer function and a reference transfer function independently. The disturbance transfer function describes how the control system <NUM> reacts on disturbances <NUM>. For example, how long it takes until a control error (deviation from well plan) is eliminated. In a room heating example, a disturbance is opening of a window. The disturbance transfer function describes how fast a temperature controller for the room can adjust the heater to compensate for the open window. The reference transfer function describes how the control system <NUM> reacts if the target values <NUM> are changed. That is, how long it takes to get to the new set-point. In the room heating example, if a user changes a desired room temperature from <NUM> to <NUM>, the reference transfer function describes how long it takes until the room temperature is <NUM>. This also allows anticipating changes in a reference trajectory which could be advantageous for features like soft-landing.

Further, a discrete depth-based control system can simplify the design of the pre-control unit <NUM>. Pre-control unit <NUM> can be based on knowledge or analysis of the control system <NUM>. For example, if it is known that it requires <NUM>% force to achieve a build-up rate of <NUM>°/100ft, then the pre-control unit <NUM> can directly apply that force when it is desired to have a build-up rate of <NUM>°/100ft. The control unit <NUM> now only needs to compensate for control errors. The pre-filter <NUM> can provide for changing control variables such as to provide faster reaction to changes in target values <NUM>. For example, in the room heating example, suppose it is desired to increase room temperature from <NUM> to <NUM>. This is a step of <NUM> which would, for example, require the heater to increase power by 100W. In order to speed up the heating, a pre-filter could be used which changes the <NUM>° step to a target temperature of <NUM> for <NUM> minutes and then to <NUM>. Accordingly, the heater could increase power by 500W for the first <NUM> minutes and then 100W for the rest of the time. Accordingly, as will be appreciated by those of skill in the art, the pre-filter <NUM> and pre-control unit <NUM> can provide improvement to an overall control system, as provided herein.

In one or more embodiments, discrete depth-based control may use a model predictive control unit as illustrated in <FIG>. A model predictive control unit <NUM> solves an optimization problem every discretization drilled distance interval (i.e., every selected drilled distance interval). The optimization may be based on a drill-ahead model that includes target values <NUM> of a control system <NUM> to predict how downhole tools and/or devices <NUM> may react on input parameter changes. The optimization problem may also consider costs for downlinks, the optimal time when to send a downlink, which actuator to use for influencing a desired trajectory, etc. Furthermore switching between several optimization objectives (e.g., drill as fast as possible, drill with minimum wear, control hold distance to formation layer, etc.) may be implemented. Because the optimization is dependent on a model, some adaptation mechanisms may be used. For example, downhole measurements <NUM> may be used to update model parameters within the model predictive control unit <NUM>, as shown.

Another potential effect which has a significant influence on the trajectory control of a steering unit and/or BHA can be a time lag or time delay of sensor signals. Because directional and formation evaluation sensors are traditionally mounted several meters behind the disintegrating device, the information about changes in the drilled trajectory is measured with a delay relative to the actual change. That is, downhole sensors can only sense a change once they have reached the change, and thus the disintegrating device has moved further into the trajectory. The time difference of the time when the disintegrating device reaches a change and the time a downhole sensor sense the change is highly dependent on ROP which is usually not constant and not predictable as it depends on many factors, some of which are difficult or impossible to control. This can result in a suboptimal control performance and can lead to an unstable control resulting in borehole undulations. When using a discrete depth-based control algorithm, as provided herein, a depth-delay between disintegrating device and sensor is constant and can be compensated quite easily through a constant delay element for the trajectory plan before comparison with the actual position. The offset-compensation may also be based on a drill tubular model and/or may use additional sensor information (e.g., derived from bending moment sensors in the BHA).

Exceptions to discrete depth-based control may be handled by procedures. There are several drilling situations where an automated trajectory control system is presumably not working (e.g., reaming, drilling on a stringer, etc.). These situations may be detected and covered by electronic procedures which advise (or automatically apply) optimal set-points for the current situation.

An appropriate control approach for a current situation may be selected by automatically switching between different control approaches, control parameterizations, and/or other control concepts (e.g., electronic procedures). Electronic procedures may be used to supervise the control and switch control laws, if required.

<FIG> is a flow process for one non-limiting example of a process <NUM> for controlling a trajectory of a borehole being drilled into the earth. The process <NUM> can be performed with drilling systems and/or control systems as shown and described above. Various components may be located on the surface while other components may be located downhole, such as described in various embodiments above. Those of skill in the art will appreciate that the above described embodiments and configurations are not to be limiting, and the process <NUM> can be performed by other drilling systems as known in the art.

Block <NUM> calls for drilling a borehole with a drilling system having a drill tubular and a disintegrating device coupled to the drill tubular.

Block <NUM> calls for steering the disintegrating device using a steering system coupled to the drill tubular and configured to receive steering control outputs/steering system inputs in order to steer the disintegrating device. As noted above, the steering system is inclusive of components that are configured to receive a steering control outputs/steering system inputs and influence the trajectory and/or orientation of the drill tubular and thus the disintegrating device according to the steering control outputs/steering system inputs in order to drill the borehole in a predictable manner. The components may include downhole components such as a rotary steering system and/or surface components such as a top-drive or mud pump.

Block <NUM> calls for providing steering control outputs/steering system inputs to the steering system using a control unit configured to provide depth-based control (e.g., as described above). For example, a control algorithm can be employed and provided having a mathematical model describing behavior of the drilling operation (e.g., the steering system) as a function of drilled distance.

The flow process <NUM> can also include a step of receiving a position, orientation, inclination, and/or azimuth of a BHA. The BHA is coupled to the drill tubular and can provide feedback signals from the drilling system. For example, sensors disposed on the BHA can detect and/or measure position, orientation, inclination, and/or azimuth of the BHA as sensed data. The sensed data can be sent to the control unit of the drilling system (either on the surface or downhole). In one or more embodiments, the sensors are configured to sense a position of the BHA and the flow process <NUM> will further include correcting the position of the BHA to provide a position of the disintegrating device.

The flow process <NUM>, in some embodiments, can also include controlling an actuator in a steering system to control a trajectory of the borehole being drilled. In one or more embodiments, the actuator is coupled to a pad of a rotary steering system. The pad can contact a wall of the borehole and apply force thereto to steer the disintegrating device in accordance with control signals from the control system.

The flow process <NUM>, in some embodiments, can also include formation parameter or characteristic information. For example, the flow process <NUM> may further include a process of sensing a parameter of a formation using a formation evaluation sensor or tool disposed on the drill tubular. A formation evaluation feedback signal can then be sent from the formation evaluation sensor or tool to the controller or a control unit. The flow process <NUM> can further include controlling a drilling trajectory to maintain a distance from, for example, formation cap rocks, formation layers, oil-water contacts, a formation layer, a formation layer boundary, etc. within a selected range of distance, using the formation evaluation feedback signal from the formation evaluation sensors or tools.

The flow process <NUM> can also include correcting a received BHA or disintegrating device (e.g., drill bit) position derived from data or a sensor in order to account for bending of the drill tubular in the borehole or stretching/squeezing of the drill tubular due to the force of gravity, pressure differences, temperatures, etc. acting on the drilling assembly and drill tubular.

In support of the teachings herein, various analysis components may be used, including a digital and/or an analog system. For example, the downhole electronics, the computer processing systems, the downhole sensors, the drilling/production parameter controllers, the steering systems, the actuators and/or other components discussed herein may include digital and/or analog systems. Further, the systems and configurations described herein may have components such as processors, storage media, memory, inputs, outputs, communications links (e.g., wired, wireless, pulsed mud, optical, acoustic, electromagnetic, etc.), user interfaces (e.g., display, printer, etc.), software programs, signal processors (e.g., digital, analog) and other such components (e.g., resistors, capacitors, inductors, etc.) to provide for operation and analyses of the apparatus and processes disclosed herein in any of several manners well-appreciated in the art. It is considered that these teachings may be, but need not be, implemented in conjunction with a set of computer executable instructions stored on a non-transitory computer readable medium, including memory (ROMs, RAMs), optical (CD-ROMs), or magnetic (disks, hard drives), or any other type that when executed causes a computer to implement the method of the present disclosure. These instructions may provide for equipment operation, control, data collection and analysis and other functions deemed relevant by a system designer, owner, user or other such personnel, in addition to the functions described in this disclosure.

Embodiment <NUM>: An apparatus for controlling a trajectory of a borehole being drilled into the earth, the apparatus comprising: a drilling system including a drill tubular, a disintegrating device, and a steering system coupled to the drill tubular configured to steer the drilling system, the drilling system configured to drill the borehole by receiving control outputs from at least one control unit for controlling parameters of the drilling system, the at least one control unit configured to provide the control outputs to the steering system, the at least one control unit being configured to provide depth-based control.

Embodiment <NUM>: The apparatus according to any of the preceding embodiments, wherein the control unit receives and uses data indicative of measured depth to provide the depth-based control.

Embodiment <NUM>: The apparatus according to any of the preceding embodiments, wherein the data indicative of measured depth is generated at the earth's surface or derived from data generated at the earth's surface.

Embodiment <NUM>: The apparatus according to any of the preceding embodiments, wherein the control unit comprises a trajectory control unit configured to control a trajectory of the borehole being drilled and/or an inclination/azimuth control unit configured to control the inclination and/or an azimuth of the borehole being drilled.

Embodiment <NUM>: The apparatus according to any of the preceding embodiments, wherein at least one of the trajectory control unit or the inclination/azimuth control unit is located downhole.

Embodiment <NUM>: The apparatus according to any of the preceding embodiments, further comprising at least one sensor coupled to the drilling system and configured to measure data indicative of a position, orientation, inclination, and/or azimuth of the sensor and provide the measured data to the at least one control unit.

Embodiment <NUM>: The apparatus according to any of the preceding embodiments, wherein the trajectory control unit is configured to provide a control output to the inclination/azimuth control unit and the inclination/azimuth control unit is configured to receive the sensed data indicative of inclination and/or azimuth.

Embodiment <NUM>: The apparatus according to any of the preceding embodiments, further comprising at least one actuator control unit configured to control at least one actuator, the at least one actuator configured to change at least one drilling parameter of the drilling system, the at least one actuator control unit receiving control outputs from the control unit.

Embodiment <NUM>: The apparatus according to any of the preceding embodiments, wherein the actuator is coupled to a pad of a rotary steering system configured to contact a wall of the borehole for steering the drilling system.

Embodiment <NUM>: The apparatus according to any of the preceding embodiments, wherein the actuator is coupled to a bent motor system, the actuator configured to change the bent of the motor.

Embodiment <NUM>: The apparatus according to any of the preceding embodiments, further comprising at least one formation evaluation sensor disposed on the drilling system and configured to sense a parameter of a formation, the formation evaluation sensor configured to provide the sensed parameter to the at least one control unit.

Embodiment <NUM>: The apparatus according to any of the preceding embodiments, wherein the at least one formation evaluation sensor comprises at least one of a gamma-ray detector, a resistivity sensor, an acoustic sensor, an NMR sensor, or a nuclear sensor.

Embodiment <NUM>: A method for controlling a trajectory of a borehole being drilled into the earth, the method comprising: drilling a borehole with a drilling system comprising a drill tubular and disintegrating device coupled to the drill tubular; and steering the disintegrating device with a steering system coupled to the drill tubular and configured to receive steering control outputs from at least one control unit in order to steer the disintegrating device, the at least one control unit configured to provide depth-based control.

Embodiment <NUM>: The method according to any of the preceding embodiments, wherein the control unit receives and uses data indicative of measured depth to provide the depth-based control.

Embodiment <NUM>: The method according to any of the preceding embodiments, further comprising generating the data indicative of measured depth is generated at the earth's surface or derived from data generated at the earth's surface.

Embodiment <NUM>: The method according to any of the preceding embodiments, further comprising receiving with the at least one control unit data indicative of at least one of a depth, position, orientation, inclination, and/or azimuth of a bottom hole assembly (BHA) coupled to the drill tubular.

Embodiment <NUM>: The method according to any of the preceding embodiments, wherein the at least one control unit comprises a trajectory control unit configured to control a trajectory of the borehole being drilled and/or an inclination/azimuth control unit configured to control the inclination and/or azimuth of the borehole being drilled.

Embodiment <NUM>: The method according to any of the preceding embodiments, further comprising controlling an actuator in the steering system in order to control the trajectory of the borehole being drilled.

Embodiment <NUM>: The method according to any of the preceding embodiments, further comprising (i) sensing a parameter of a formation using a formation evaluation sensor disposed on the drilling system and (ii) providing a signal indicative of a measured output from the formation evaluation sensor to the at least one control unit.

Embodiment <NUM>: The method according to any of the preceding embodiments, further comprising identifying at least one formation feature by using the parameter of a formation and controlling by the at least one control unit the steering system to maintain a distance from the at least one formation feature.

Elements of the embodiments have been introduced with either the articles "a" or "an. " The articles are intended to mean that there are one or more of the elements. The terms "including" and "having" are intended to be inclusive such that there may be additional elements other than the elements listed. The conjunction "or" when used with a list of at least two terms is intended to mean any term or combination of terms. The term "configured" relates to one or more structural limitations of a device that are required for the device to perform the function or operation for which the device is configured.

The flow diagrams and schematic diagrams depicted herein are just examples. There may be many variations to these diagrams or the steps (or operations) described therein without departing from the present disclosure. For instance, the steps may be performed in a differing order, or steps may be added, deleted or modified. All of these variations are considered a part of the claims appended herewith.

While one or more embodiments have been shown and described, modifications and substitutions may be made thereto without departing from the present disclosure. Accordingly, it is to be understood that the present disclosure has been described by way of illustrations and not limitation.

It will be recognized that the various components or technologies may provide certain necessary or beneficial functionality or features. Accordingly, these functions and features as may be needed in support of the appended claims and variations thereof, are recognized as being inherently included as a part of the teachings herein and a part of the embodiments disclosed and/or variations thereof.

Claim 1:
An apparatus for controlling a trajectory of a borehole (<NUM>, <NUM>) being drilled into the earth, the apparatus comprising:
a drilling system (<NUM>, <NUM>) including a drill tubular, a disintegrating device (<NUM>), and a steering system (<NUM>) coupled to the drill tubular configured to steer the drilling system (<NUM>, <NUM>), and
at least one control unit (<NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>, <NUM>),
the drilling system (<NUM>, <NUM>) configured to drill the borehole (<NUM>, <NUM>) by receiving control outputs from the at least one control unit (<NUM>, ... , <NUM>) for controlling parameters of the drilling system (<NUM>, <NUM>),
the at least one control unit (<NUM>, ... , <NUM>) configured to provide the control outputs to the steering system (<NUM>), and
characterized in that:
the at least one control unit is configured to provide depth-based control, wherein the control unit receives and uses data indicative of drilled distance to provide the depth-based control, wherein new control outputs are calculated at: (i) predetermined drilled distances; or (ii) predetermined drilled distance intervals; and
wherein the control outputs are calculated using an equation that is time-independent.