GAIN CONTROL FOR STEERING DOWNHOLE TOOL

Description

FIELD

The present invention relates generally to oil field drilling. More particularly, the present invention relates to control of rotatable steering systems in an oil field drilling operation.

BACKGROUND

Rotatable steering systems (“RSS”) allow for greater automation in directional drilling. RSS systems typically include a steering algorithm that reduces human-machine interaction, reduces reliance on previously computed survey models, and reduces the need to conduct static surveys with conventional measurement-while-drilling (“MWD”) tools.

RSS systems implement autonomous downhole control systems, including hold inclination and azimuth (“HIA”) systems, automated inclination hold (“IH”) systems, and other autonomous control systems (e.g., “Auto-curve” implemented in SLB's PowerDrive RSS tools). Autonomous downhole control systems compare actual inclination and azimuth against a target inclination and azimuth to make frequent, small adjustments to the RSS's steering parameters with the goal of decreasing well tortuosity. Sensors in a downhole tool capture the inclination and azimuth measurements. The sensors included in a downhole tool include a magnetometer, an accelerometer, and gyroscope sensors.

In addition to the small adjustments made by the autonomous downhole control systems, downhole tools are steered through a desired drill path trajectory in response to steering controls downlinked by an operator on the surface. Steering the downhole tool involves sending commands to change the tool's inclination and azimuth to control the downhole tool through the desired drill path trajectory or to correct any deviations from the desired drill path trajectory. The amount of force or change implemented by the RSS to steer the downhole tool according to the steering command can be referred to as “gain”.

If a gain setting is incorrect or inaccurate in an RSS, the result can be increased wellbore tortuosity in the curve, tangent, horizontal, and lateral sections of the well. Increased wellbore tortuosity can result in additional downlinking, lowered rate of penetration (“ROP”), increased wear and tear on component parts, and, in some case, non-productive time.

Conventional RSS systems have a relatively small number of gain settings that correspond to relatively large ROP ranges. For example, a conventional RSS system may include two gain settings that correspond to two relatively large ROP ranges (e.g., 95% for ROP range 20-100 feet/hour and 80% for ROP range 80-400 feet/hour). These gain settings may imprecisely steer a downhole tool for some or many of the ROP values in the relatively large ROP range or these gain settings may correct drill path trajectory slower than a more accurate gain setting would have corrected drill path trajectory.

Additionally, RSS systems fail to account for the increased ROP of some RSS systems (e.g., up to 800 feet/hour). Because these conventional gain settings do not specifically correlate with faster ROP, RSS tools could induce stick/slip or increase friction and hole cleaning issues. As such, there is an ongoing need for improved gain settings in an RSS.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a data processing system in which an illustrative embodiment of the present invention may be implemented;

FIGS. 2A and 2B illustrate plots of a downhole tool's inclination angle over time in response to two different gain settings according to an embodiment;

FIG. 3 illustrates a computing system according to an embodiment; and

FIG. 4 illustrates a flow chart for identifying or calculating a gain value for steering operations of a downhole tool based on ROP according to an embodiment.

DETAILED DESCRIPTION

While this invention is susceptible of an embodiment in many different forms, there are shown in the drawings and will be described herein in detail specific embodiments thereof with the understanding that the present disclosure is to be considered as an exemplification of the principles of the invention. It is not intended to limit the invention to the specific illustrated embodiments.

Embodiments disclosed herein can include systems and methods that identify or calculate a variable gain for steering parameters based on an ROP of a downhole tool. The downhole tool can receive an ROP value via downlinking and identify or calculate the variable gain value based on the received ROP value. Downlinking in the drilling industry refers to the process of communicating from the surface or from drilling rigs to the downhole tool. Downlinking allows an operator from the surface to send various commands to the downhole tool, including steering commands. The ROP value can be downlinked with pre-nudge commands (that is commands received via downlinking before any steering commands are received). Alternatively, the ROP value may be downlinked as part of a steering command or with any other downlinking operation.

A steering algorithm implemented by the downhole tool to perform steering operations can receive data from the sensors to measure a trajectory of the downhole tool, determine a difference in the measured trajectory of the downhole tool from a desired trajectory, and transform the difference into a steering force ratio of an applied force in a given direction for a set period necessary to correct the trajectory of the downhole tool so that the downhole tool implements the steering controls and follows the desired trajectory.

More specifically, the steering algorithm can calculate the difference between an actual inclination and a desired inclination using sensor readings. In response to the calculated difference, the steering algorithm applies the gain and a correction for gravity. Subsequently, the steering algorithm can calculate what steering setting is required to achieve the desired inclination. The calculated steering setting changes a proportion of time in a drill cycle that is steering as opposed to being neutral. The steering vs. neutral proportion of time may be called the steering ratio.

The downhole tool accounts for ROP before the downhole tool attempts to correct the difference in trajectory as the downhole tool could oscillate around the target trajectory. A gain factor called an “ROP Index” can be applied to the steering ratio to prevent or mitigate the oscillation. The value of the gain (ROP Index) applied by the controller to the difference in trajectory impacts the calculation of the steering ratio and thus, how aggressively the tool responds to correct the steering and achieve the desired trajectory. The amount of over-correction (or under correction) of the trajectory may be directly linked to the size of this gain value (ROP Index). This steering force ratio is called “gain” herein. Moreover, the steering can account for or be based on the ROP of the downhole tool. The correction is generally applied in a fraction of time when the steering force in the desired direction is applied. Currently, the steering algorithm has a gain set in the maintenance facility or sent via downlink at the rig site and implemented for HIA, IA IH, or any other autonomous control feature, which can correct any deflection of the downhole tool caused by a hard stinger or desirable or undesirable change trajectory.

The downhole tool can include firmware, software, or any other computer-readable code that can calculate or identify an appropriate gain setting for the ROP value received. The gain identified or calculated may be a variable gain setting, and the number of variable gain settings may be infinite based on calculations. In an alternative embodiment, the gain settings may be saved in a look-up table to provide default gain values based on the ROP value received via downlinking.

In some embodiments, the ROP value may be calculated by the downhole tool based on sensor readings, and the ROP value need not be downlinked. After calculating or identifying an appropriate gain setting based on current ROP, the downhole tool may implement the calculated or identified gain setting during a drilling operation. As a result, the systems and methods described herein can avoid wellbore tortuosity or “kinks” in the well.

In addition to providing the ROP value used to calculate or identify a gain value, the downhole tool can receive or store tolerances for a drilling tunnel, which can be tightened or relaxed in response to a downlinked command to tighten or relax the tolerances. In an alternative embodiment, the tolerances may be preset prior to a drilling operation. Tolerances can include allowed error from a desired trajectory. An allowed error threshold from the desired trajectory can be a tolerance received through downlinking. Depending on a well's condition, the tolerances may be relaxed or tightened to improve wellbore tortuosity and drilling speed. Tolerances can further include micro-dogleg limits.

Using the ROP and tolerances, the downhole tool can use the identified or calculated gain value to maintain a smooth wellbore trajectory. Alternatively, the downhole tool can implement a trajectory change over a number of drill cycles using smaller gain values.

In some embodiments, the steering algorithm can further adjust gain as a proportional-integral-derivative (PID) controller. In this way, the steering algorithm can implement smart gain control features to learn from errors in gain overshoot or undershoot. The smart features may adjust gain in subsequent steering nudges based on previous undershoot or overshoot. By implementing the steering algorithm as an error feedback loop, such as a PID controller, the steering algorithm can set and adjust gain for optimal overshoot and rise time. In some embodiments, gain settings can be compared against lithography to better adjust responses.

Referring to FIG. 1, a pictorial representation of a data processing system is depicted in which an illustrative embodiment of the present invention may be implemented. In this example, data processing system 100 is one or more computing devices in which different embodiments of the present invention may be implemented.

In this depicted example, well site 102 includes or is connected to a computing device 104 that produces data regarding the well site 102. This information may be used in the management of drilling operations at the well site 102. For example, the information may be used to direct drilling operations for the well site. Moreover, the computing device 104 can display data to a drilling engineer or other operator regarding a drilling operation. The operator can interact with the computing device 104 to oversee drilling operations, including generating commands provided to downhole drilling equipment through downlinking. In these examples, well site 102 is located in a geographic region 112. This geographic region 112 is a single reservoir, as described in these examples. While FIG. 1 illustrates only a single well site 102, the geographic region 112 may include a plurality of well sites at or near the reservoir strategically positioned to maximize oil or gas production.

The computing device 102 may communicate with a downhole tool 106 via downlinking. The downhole tool 106 can include a controller 107 that can implement autonomous control features, communicate with sensors included within the downhole tool 106 (sensors that can include a magnetometer, a gyroscope, and an accelerometer), and the controller 107 can also implement a steering algorithm configured to determine gain values for steering control of the downhole tool 106.

The computing device 102 may be connected to an analysis center 120 at which data processing systems are located to assist with wellbore drill path planning and real-time analysis of wellbore drilling. Depending on the particular implementation, multiple analysis centers may be present. These analysis centers may be, for example, at an office or on-site in the geographic location 112 depending on the particular implementation. In these illustrative embodiments, analysis center 120 analyzes data from computing device 102 using processes for different embodiments of the present invention. Analysis center 120 can also connect with other computing devices associated with other well sites (not illustrated). Moreover, the analysis center 120 can store past drilling data collected during previously completed drilling operations, and store present drilling data collected during an ongoing drilling operation. In some embodiments, the analysis center 120 is omitted, and the computing device 104 performs the functions described herein as being performed by the analysis center 120.

The computing device 104 may connect to the analysis center 120 via a networked connection. In an example, the networked connection can include the Internet, which includes a worldwide collection of networks and gateways that use the Transmission Control Protocol/Internet Protocol (TCP/IP) suite of protocols to communicate with one another. Of course, the networked connection also may be implemented as a number of different types of networks, such as, for example, an intranet, a local area network (LAN), or a wide area network (WAN). FIG. 1 is intended as an example, and not as an architectural limitation for different embodiments.

FIGS. 2A and 2B illustrate plots of a downhole tool's inclination angle over time in response to two different gain settings according to an embodiment. In both FIG. 2A and FIG. 2B, a downhole tool should change from a 40° inclination angle to a 40.5° inclination angle based on a desired drill path. The solid line 202 illustrates a desired trajectory. To achieve the change from the 400 inclination angle to the 40.5° inclination angle, the downhole tool can receive multiple downlinked commands 204 over time. In FIG. 2A, the downhole tool received the downlinked commands 204, and applied a gain value that was too high. As a result, the downhole tool's actual inclination angle 206A overshot the desired trajectory by a significant margin (almost to 40.8°). Adjustments were made but it took a very long time (almost 16000 seconds) to steer the tool toward the correct inclination angle.

In contrast, in FIG. 2B, the downhole tool received the same downlinked commands 204, and applied a more accurate gain value. As a result, the downhole tool's actual inclination angle 206B barely overshot the desired trajectory (not even rising to 40.6°), and the downhole tool required almost 7000 fewer seconds to steer the tool to the correct inclination angle. The difference between FIG. 2A and FIG. 2B illustrates the importance of setting an appropriate gain value for steering the downhole tool. The difference between FIG. 2A and FIG. 2B further illustrates that setting the appropriate gain value reduces wellbore tortuosity.

Turning now to FIG. 3, a diagram of a computing system is depicted in accordance with an illustrative embodiment. In this illustrative example, the computing system 300 includes a communications bus 302, which provides communications between a processor unit 304, memory 306, persistent storage 308, a communications unit 310, an input/output (I/O) unit 312, and a display 314. The computing system 300 of FIG. 3 can depict the components of the controller 107 in FIG. 1.

The processor unit 304 serves to execute instructions for software that may be loaded into memory 306. The processor unit 304 may comprise one or more processors or may be a multi-processor core, depending on the particular implementation. Further, the processor unit 304 may be implemented using one or more heterogeneous processor systems in which a main processor is present with secondary processors on a single chip. In another illustrative example, the processor unit 304 may be a symmetric multi-processor system containing multiple processors of the same type.

The memory 306, in these examples, may be, for example, a random access memory or any other suitable volatile or non-volatile storage device. The persistent storage 308 may take various forms depending on the particular implementation. For example, the persistent storage 308 may contain one or more components or devices. For example, the persistent storage 308 may be a hard drive, a flash memory, a rewritable optical disk, a rewritable magnetic tape, or some combination of the above. The media used by the persistent storage 308 also may be removable. For example, a removable hard drive may be used for the persistent storage 308. In another embodiment, the persistent storage 308 may comprise a database.

The communications unit 310, in these examples, provides for communications with other data processing systems or devices. In these examples, the communications unit 310 is a network interface card. The communications unit 310 may provide communications through either or both physical and wireless communications links.

The input/output unit 312 allows for input and output of data with other devices that may be connected to the computing system 300. For example, the input/output unit 312 may provide a connection for user input number pad or keyboard. The display 314 provides a mechanism to display information to a user. In some embodiments, the communications unit 310, the input/output unit 312, and the display 314 may be omitted.

Instructions for the operating system and applications or programs are located on the persistent storage 308. These instructions may be loaded into the memory 306 for execution by the processor unit 304. The processes of the different embodiments may be performed by the processor unit 304 using computer implemented instructions, which may be located in a memory, such as the memory 306. These instructions are referred to as, program code, computer usable program code, or computer readable program code that may be read and executed by a processor in the processor unit 304. The program code in the different embodiments may be embodied on different physical or tangible computer readable media, such as the memory 306 or the persistent storage 308.

The program code 316 is located in a functional form on computer readable media 318 and may be loaded onto or transferred to the computing system 300 for execution by the processor unit 304. The program code 316 and the computer readable media 318 form computer program product 320 in these examples. In one example, the computer readable media 318 may be in a tangible form, such as, for example, an optical or magnetic disc that is inserted or placed into a drive or other device that is part of the persistent storage 308 for transfer onto a storage device, such as a hard drive that is part of the persistent storage 308. In a tangible form, the computer readable media 318 also may take the form of a persistent storage, such as a hard drive or a flash memory that is connected to the computing system 300. The tangible form of the computer readable media 318 is also referred to as computer recordable storage media. In some embodiments, the program code may update firmware within the persistent storage 308 of the computing system 300.

Alternatively, the program code 316 may be transferred to the computing processing system 300 from the computer readable media 318 through a communications link to the communications unit 310 and/or through a connection to the input/output unit 312. The communications link and/or the connection may be physical or wireless in the illustrative examples. The computer readable media also may take the form of non-tangible media, such as communications links or wireless transmissions containing the program code. In one particular embodiment, the program code 316 can comprise one or more steering algorithms configured to identify or calculate gain settings for a downhole tool.

The different components illustrated for the data processing system 300 are not meant to provide architectural limitations to the manner in which different embodiments may be implemented. The different illustrative embodiments may be implemented in a data processing system including components in addition to or in place of those illustrated for the data processing system 300. Other components shown in FIG. 3 can be varied from the illustrative examples shown.

For example, a bus system may be used to implement communications bus 302 and may be comprised of one or more buses, such as a system bus or an input/output bus. Of course, the bus system may be implemented using any suitable type of architecture that provides for a transfer of data between different components or devices attached to the bus system. Additionally, a communications unit may include one or more devices used to transmit and receive data, such as a modem or a network adapter. Further, a memory may be, for example, memory 306 or a cache, such as found in an interface and memory controller hub that may be present in communications bus 302.

FIG. 4 illustrates a method 400 for identifying or calculating a gain value for steering operations of a downhole tool based on ROP according to an embodiment. As shown, the method 400 includes a processor, such as the processor unit 304 in FIG. 3, identifying the ROP of a downhole tool, such as downhole tool 106 in FIG. 1, in step 402. According to an embodiment, the processor can identify ROP by receiving the ROP value via downlinking. Alternatively, the processor can calculate the ROP after receiving one or more measurements from sensors included in the downhole tool.

Subsequently, the processor can determine whether any other factors impact gain settings in step 404. For example, the processor can determine whether the downhole tool has been programmed or preset with any tolerances that impact gain settings. In another embodiment, additional well condition data may be stored or received and considered as a factor in calculating the gain value. Subsequently, the processor calculates the gain value based on the ROP and any other factors in step 406.

After calculating the gain, the processor can implement the gain value from step 406 in a steering operation in step 408. Furthermore, the processor can correct the gain value in step 410. Correcting the gain value can include implementing an error feedback loop, such as a PID controller, to determine whether to increase or decrease the gain value for subsequent steering operations. The processor can reference sensor values to determine whether the gain value was too large or too small. For example, the processor can reference sensors to determine whether the implemented gain value in step 408 resulted in a desired inclination angle and azimuth. If additional corrections are necessary, the processor can save the data, update the gain settings for future steering operations, and provide error feedback through a PID controller. The processor can store error feedback data in memory, such as the memory 306 or the persistent storage 308 of FIG. 3, which can be referenced in future gain calculations for future steering or nudge commands. In addition, in some embodiments, the error feedback data can be compared against lithography to better adjust gain value settings.

Although not illustrated, the method 400 can further include receiving new tolerance values via downlinking. The new error tolerances may tighten or loosen existing error tolerances in deviation from a desired drill path or tool trajectory. In another embodiment, the tolerances may be loosened or tightened as part of step 410. For example, the processor may correct the gain value by lowering the gain value assigned for the current ROP, and the processor can also tighten the tolerances so that large gain values are not required to correct any deviations from the drill path as part of the HIA or IH features of an RSS tool.

The tool solves the problems over the prior art because the gain applied will more accurately reflect the ROP of the downhole tool, which will correct steering parameters more accurately and decrease well tortuosity. Indeed, by correlating gain parameters variably with ROP values, the systems and methods here can increase ROP, improve hole cleaning, reduce downlinking, and lower the wear and tear on component parts.

Although a few embodiments have been described in detail above, other modifications are possible. For example, the steps described above do not require the particular order described or sequential order to achieve desirable results. Other steps may be provided, steps may be eliminated from the described flows, and other components may be added to or removed from the described systems. Other embodiments may be within the scope of the invention.

From the foregoing, it will be observed that numerous variations and modifications may be effected without departing from the spirit and scope of the invention. It is to be understood that no limitation with respect to the specific system or method described herein is intended or should be inferred. It is, of course, intended to cover all such modifications as fall within the spirit and scope of the invention.