Patent Application
20170218747
Oil wells are created by drilling a hole into the earth using a drilling rig that rotates a drill string (e.g., drill pipe) having a drill bit attached thereto. The drill bit, aided by the weight of pipes (e.g., drill collars) cuts into rock within the earth. Drilling fluid (e.g., mud) is pumped into the drill pipe and exits at the drill bit. The drilling fluid may be used to cool the bit, lift rock cuttings to the surface, at least partially prevent destabilization of the rock in the wellbore, and/or at least partially overcome the pressure of fluids inside the rock so that the fluids do not enter the wellbore.
Aspects of the disclosure can relate to a method for simulating expected sensor values associated with a drill tool (e.g., a drill assembly) before drilling, to monitor the sensor. A planned trajectory for the drill assembly is received, where the planned trajectory is associated with a borehole to be drilled by the drill assembly along a geographic path. An expected position for the drill assembly is determined along the geographic path. An expected sensor value for a sensor associated with the drill assembly is simulated at the expected position. Next, an actual sensor value at an actual position corresponding to the expected position is determined. Then, the expected sensor value and the actual sensor value are dynamically displayed together at a user interface.
Other aspects of the disclosure can relate to a system for simulating expected sensor values associated with a drill assembly before drilling to monitor the sensor. A memory is operable to store one or more modules. A processor is operably coupled to the memory, and the processor is operable to execute the one or more modules to receive a planned trajectory for the drill assembly, where the planned trajectory is associated with a borehole to be drilled by the drill assembly along a geographic path. The processor is also operable to execute the one or more modules to determine an expected position for the drill assembly along the geographic path, and simulate an expected sensor value for a sensor associated with the drill assembly at the expected position. The system can also include a sensor configured to determine an actual sensor value at an actual position corresponding to the expected position, and a user interface configured to dynamically display the expected sensor value and the actual sensor value together.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
Embodiments of determining expected sensor values for a borehole are described with reference to the following figures.
Oil and gas well drilling operations can use sensors deployed down hole (e.g., as part of a drill string) to acquire information as a wellbore is being drilled. For example, during the drilling of a borehole, multiple sensor readings from down hole drilling tools are received at the surface. This real-time data can provide information about the progress of the drilling operation, earth formations surrounding the borehole, and so on. Operations personnel often monitor the measured values with a limited understanding of values that could be expected from the sensors when following the prescribed well trajectory. Further, the range of acceptable values of these sensor readings can be a function of various factors, including, but not necessarily limited to geographic factors, geometric factors, geophysical conditions, and so forth. Variations of operator training and/or experience levels may result in incorrect conclusions regarding tool performance (e.g., based upon operator interpretation of the sensor values). Thus, in some cases, sensor values received from correctly functioning tools may be interpreted as indicative of tool failure (e.g., when unexpected changes are observed in sensor values, sensor value changes do not follow expectations, and so on). For instance, a cause of sensor value misinterpretation can be the complexity of dynamically changing spatial relations between wellbore trajectory and gravity and/or geomagnetic fields.
Systems and methods for wellbore magnetic surveying are described herein that can provide specific monitoring guidance information for operations personnel during borehole trajectory planning activities. Reducing and/or eliminating misinterpretation of survey sensor data by presenting expected sensor values for a correctly operating tool and a reasonably followed planned trajectory can be provided to a drilling equipment operator. As described herein, planned borehole trajectory orientations and modeled geophysical values of geomagnetic field data and/or gravity field data can be used to generate expected values that a down hole surveying tool may measure on multi-axis accelerometers, magnetometers, and so forth. Specific sensor value ranges can be provided along the planned trajectory of a drill assembly, which can be compared to measured sensor readings determined during drilling. The expected values generated can be used during wellbore construction by personnel to verify that actual measured sensor values are in an expected range as defined by the generated values from the plan. This technique can reduce or eliminate misinterpretation of measured data as erroneous (e.g., due to simplification of the complex spatial relationship between the down hole survey tool orientation and the geophysical field orientations). As described herein, drilling applications are provided by way of example and are not meant to limit the present disclosure. In other embodiments, systems, techniques, and apparatus as described herein can be used with other down hole operations. Further, such systems, techniques, and apparatus can be used in other applications not necessarily related to down hole operations.
A bottom hole assembly (BHA) 116 is suspended at the end of the drill string 104. The bottom hole assembly 116 includes a drill bit 118 at its lower end. In embodiments of the disclosure, the drill string 104 includes a number of drill pipes 120 that extend the bottom hole assembly 116 and the drill bit 118 into subterranean formations. Drilling fluid (e.g., mud) 122 is stored in a tank and/or a pit 124 formed at the wellsite. The drilling fluid 122 can be water-based, oil-based, and so on. A pump 126 displaces the drilling fluid 122 to an interior passage of the drill string 104 via, for example, a port in the rotary swivel 114, causing the drilling fluid 122 to flow downwardly through the drill string 104 as indicated by directional arrow 128. The drilling fluid 122 exits the drill string 104 via ports (e.g., courses, nozzles) in the drill bit 118, and then circulates upwardly through the annulus region between the outside of the drill string 104 and the wall of the borehole 102, as indicated by directional arrows 130. In this manner, the drilling fluid 122 cools and lubricates the drill bit 118 and carries drill cuttings generated by the drill bit 118 up to the surface (e.g., as the drilling fluid 122 is returned to the pit 124 for recirculation). Further, destabilization of the rock in the wellbore can be at least partially prevented, the pressure of fluids inside the rock can be at least partially overcome so that the fluids do not enter the wellbore, and so forth.
In embodiments of the disclosure, the drill bit 118 comprises one or more crushing and/or cutting implements, such as conical cutters and/or bit cones having spiked teeth (e.g., in the manner of a roller-cone bit). In this configuration, as the drill string 104 is rotated, the bit cones roll along the bottom of the borehole 102 in a circular motion. As they roll, new teeth come in contact with the bottom of the borehole 102, crushing the rock immediately below and around the bit tooth. As the cone continues to roll, the tooth then lifts off the bottom of the hole and a high-velocity drilling fluid jet strikes the crushed rock chips to remove them from the bottom of the borehole 102 and up the annulus. As this occurs, another tooth makes contact with the bottom of the borehole 102 and creates new rock chips. In this manner, the process of chipping the rock and removing the small rock chips with the fluid jets is continuous. The teeth intermesh on the cones, which helps clean the cones and enables larger teeth to be used. A drill bit 118 comprising a conical cutter can be implemented as a steel milled-tooth bit, a carbide insert bit, and so forth. However, roller-cone bits are provided by way of example and are not meant to limit the present disclosure. In other embodiments, a drill bit 118 is arranged differently. For example, the body of the drill bit 118 comprises one or more polycrystalline diamond compact (PDC) cutters that shear rock with a continuous scraping motion.
In some embodiments, the bottom hole assembly 116 includes a logging-while-drilling (LWD) module 132, a measuring-while-drilling (MWD) module 134, a rotary steerable system 136, a motor, and so forth (e.g., in addition to the drill bit 118). The logging-while-drilling module 132 can be housed in a drill collar and can contain one or a number of logging tools. It should also be noted that more than one LWD module and/or MWD module can be employed (e.g. as represented by another logging-while-drilling module 138). In embodiments of the disclosure, the logging-while drilling modules 132 and/or 138 include capabilities for measuring, processing, and storing information, as well as for communicating with surface equipment, and so forth.
The measuring-while-drilling module 134 can also be housed in a drill collar, and can contain one or more devices for measuring characteristics of the drill string 104 and drill bit 118. The measuring-while-drilling module 134 can also include components for generating electrical power for the down hole equipment. This can include a mud turbine generator powered by the flow of the drilling fluid 122. However, this configuration is provided by way of example and is not meant to limit the present disclosure. In other embodiments, other power and/or battery systems can be employed. The measuring-while-drilling module 134 can include one or more of the following measuring devices, a direction measuring device, an inclination measuring device, and so on. Further, a logging-while-drilling module 132 and/or 138 can include one or more measuring devices, such as a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, and so forth.
In some embodiments, the wellsite system 100 is used with controlled steering or directional drilling. For example, the rotary steerable system 136 is used for directional drilling. As used herein, the term “directional drilling” describes intentional deviation of the wellbore from the path it would naturally take. Thus, directional drilling refers to steering the drill string 104 so that it travels in a desired direction. In some embodiments, directional drilling is used for offshore drilling (e.g., where multiple wells are drilled from a single platform). In other embodiments, directional drilling enables horizontal drilling through a reservoir, which enables a longer length of the wellbore to traverse the reservoir, increasing the production rate from the well. Further, directional drilling may be used in vertical drilling operations. For example, the drill bit 118 may veer off of a planned drilling trajectory because of the unpredictable nature of the formations being penetrated or the varying forces that the drill bit 118 experiences. When such deviation occurs, the wellsite system 100 may be used to guide the drill bit 118 back on course.
The drill string 104 can include one or more extendable displacement mechanisms, such as a piston mechanism that can be selectively actuated by an actuator to displace a pad toward, for instance, a borehole wall to cause the bottom hole assembly 116 to move in a desired direction of deviation. In embodiments of the disclosure, a displacement mechanism can be actuated by the drilling fluid 122 routed through the drill string 104. For example, the drilling fluid 122 is used to move a piston, which changes the orientation of the drill bit 118 (e.g., changing the drilling axis orientation with respect to a longitudinal axis of the bottom hole assembly 116). The displacement mechanism may be employed to control a directional bias and/or an axial orientation of the bottom hole assembly 116. Displacement mechanisms may be arranged, for example, to point the drill bit 118 and/or to push the drill bit 118. In some embodiments, a displacement mechanism is deployed by a drilling system using a rotary steerable system 136 that rotates with a number of displacement mechanisms. It should be noted that the rotary steerable system 136 can be used in conjunction with stabilizers, such as non-rotating stabilizers, and so on.
In some embodiments, a displacement mechanism can be positioned proximate to the drill bit 118. However, in other embodiments, a displacement mechanism can be positioned at various locations along a drill string, a bottom hole assembly, and so on. For example, in some embodiments, a displacement mechanism is positioned in a rotary steerable system 136, while in other embodiments, a displacement mechanism can be positioned at or near the end of the bottom hole assembly 116 (e.g., proximate to the drill bit 118). In some embodiments, the drill string 104 can include one or more filters that filter the drilling fluid 122 (e.g., upstream of the displacement mechanism with respect to the flow of the drilling fluid 122).
Referring now to
The controller 206 can be coupled with one or more sensors 208, which can report determined values associated with a monitored operation, such as a drilling operation, to the controller 206. Example sensors 208 can include, but are not necessarily limited to: sensors associated with a logging-while-drilling module 132/138, a measuring-while-drilling module 134, a rotary steerable system 136, a drill bit 118, a motor, and so forth. For example, a measuring-while-drilling module 134 housed in a drill collar contains one or more sensors 208 for measuring characteristics of the drill string 104 and/or the drill bit 118. One or more of the sensors 208 can be coupled with the controller 206 and can communicate sensed values associated with the drill string 104 and/or the drill bit 118 to the controller 206.
In some embodiments, the system 200 includes an alert module. The alert module can be configured to provide an alert to an operator when a condition (or set of conditions) is met for monitored equipment. For example, an alert is generated when a sensor value is outside a range of expected values. In some embodiments, an alert is provided to an operator in the form of an audible and/or visual alarm. However, these alerts are provided by way of example and are not meant to limit the present disclosure. In other embodiments, different alerts are provided to an operator. For instance, an alert can be provided to an operator in the form of an email message, a text message, and so forth. Further, multiple alerts can be provided to an operator when a condition is met for the monitored equipment (e.g., an email message and a text message, and so forth).
In example embodiments, the following equations can be used to simulate expected sensor values for a drilling assembly (e.g., a down hole drilling tool that includes one or more sensors, a drill tool, and so forth, such as the wellsite system 100 described with reference to
Primary Output
Primary Input
Axial Accelerometer Reading—to be Reported
Cross-Axial Accelerometer Reading Range—to be Reported
Bhorz=Bref*cos(dipref)
Bvert=Bref*sin(dipref)
Axial Magnetometer Reading—to be Reported
By temp=Bhorz*cos(inc)*cos(azimag)−Bvert*sin(inc)
Bz temp=−Bhorz*sin(azimag)
T F(min,max)=a tan 2(By temp, Bz temp)
Note: this is the quadrant correct tangent
Cross-Axial Magnetometer Reading Range—to be Reported
In some embodiments, expected sensor values are determined that account for an actual drilling operation deviating from a planned borehole trajectory, resulting in a range of simulated values. For example, deviation from a planned path can be accounted for by running multiple simulations to generate a valid range for the axial sensors and/or a different range for the cross-axial sensors. The same equations can also be used to produce values corresponding to survey stations that deviate from the planned (e.g., ideal) trajectory orientation to simulate reasonable deviations of actual drilling from the planned trajectory, providing a wider range of values.
The following is an example calculation using techniques in accordance with the present disclosure.
Primary Input
Axial Accelerometer Reading—to be Reported
Cross-Axial Accelerometer Reading Range—to be Reported
Bhorz=43328.6736*cos(37.5518)=34351.0871(nT)
Bvert=43328.6736*sin(37.5518)=26407.8922(nT)
Axial Magnetometer Reading—to be Reported
By temp=34351.0871*cos(4.13)*cos(124.1115)−26407.8922* sin(4.13)=−21116.1308(nT)
Bz temp=−34351.0871*sin(124.1115)=−28440.9067(nT)
TF(min,max)=a tan 2(−21116.1308, −28440.9067)=−26.5923(deg)
Note: this is the quadrant correct tangent
Cross-Axial Magnetometer Reading Range—to be Reported
As described herein, expected sensor data trends can also be ascertained (e.g., increasing, decreasing, generally stable, stable, and so forth), as well as expected polarity reversals, which can be the result of the changing spatial relationship between the borehole and the geophysical measurement fields. These expected sensor data trends can be derived from graphical and/or numerical presentation of the simulation data. Further, such trends can be recorded on reports and/or within computing systems used during the drilling of the planned trajectory (e.g., as previously described).
In example embodiments, a range of expected sensor values for sensor readings can be determined based upon one or more conditions including, but not necessarily limited to, geographic conditions, geometric conditions, geophysical conditions, and so forth. Thus, in some embodiments a range can be determined based upon a rotational orientation of a tool, which can create varied readings with respect to geographic, geometric, and/or geophysical conditions. Further, a range can be reported as a maximum expected value and a minimum expected value, and may also include intermediate values, such as mean and/or median expected values. However, such conditions are provided by way of example and are not meant to limit the present disclosure. In other embodiments, a range can be determined based upon allowable deviations from a planned trajectory. For example, an expected sensor value or range of expected sensor values can be converted to another range of expected sensor values by adding and/or subtracting a percentage of an expected sensor value or range of expected sensor values. For instance, an expected sensor value can be reported as a range of expected sensor values determined based upon the expected sensor value plus or minus two-percent (+/−2%). In another example, a range of expected sensor values can be expanded (e.g., adding and/or subtracting a percentage to maximum and/or minimum expected sensor values). In this manner, expected sensor values and/or ranges of expected sensor values can be used for quality control (QC) (e.g., to ensure that sensors are working correctly and not malfunctioning). Such expected sensor values can also be used to avoid misinterpretation of sensor readings by operations personnel.
Referring now to
The controller 206 can include a processor 208, a memory 210, and a communications interface 212. The processor 208 provides processing functionality for the controller 206 and can include any number of processors, micro-controllers, or other processing systems, and resident or external memory for storing data and other information accessed or generated by the controller 206. The processor 208 can execute one or more software programs that implement techniques described herein. The processor 208 is not limited by the materials from which it is formed or the processing mechanisms employed therein and, as such, can be implemented via semiconductor(s) and/or transistors (e.g., using electronic integrated circuit (IC) components), and so forth.
The memory 210 is an example of tangible, computer-readable storage medium that provides storage functionality to store various data associated with operation of the controller 206, such as software programs and/or code segments, or other data to instruct the processor 208, and possibly other components of the controller 206, to perform the functionality described herein. Thus, the memory 210 can store data, such as a program of instructions for operating the system 200 (including its components), and so forth. It should be noted that while a single memory 210 is described, a wide variety of types and combinations of memory (e.g., tangible, non-transitory memory) can be employed. The memory 210 can be integral with the processor 208, can comprise stand-alone memory, or can be a combination of both.
The memory 210 can include, but is not necessarily limited to: removable and non-removable memory components, such as random-access memory (RAM), read-only memory (ROM), flash memory (e.g., a secure digital (SD) memory card, a mini-SD memory card, and/or a micro-SD memory card), magnetic memory, optical memory, universal serial bus (USB) memory devices, hard disk memory, external memory, and so forth. In implementations, the drill rig control module 202 and/or the memory 210 can include removable integrated circuit card (ICC) memory, such as memory provided by a subscriber identity module (SIM) card, a universal subscriber identity module (USIM) card, a universal integrated circuit card (UICC), and so on.
The communications interface 212 is operatively configured to communicate with components of the system 200. For example, the communications interface 212 can be configured to transmit data for storage in the system 200, retrieve data from storage in the system 200, and so forth. The communications interface 212 is also communicatively coupled with the processor 208 to facilitate data transfer between components of the system 200 and the processor 208 (e.g., for communicating inputs to the processor 208 received from a device communicatively coupled with the controller 206, such as a sensor 208). It should be noted that while the communications interface 212 is described as a component of a controller 206, one or more components of the communications interface 212 can be implemented as external components communicatively coupled to the system 200 via a wired and/or wireless connection. The controller 206 can also comprise and/or connect to one or more input/output (I/O) devices (e.g., via the communications interface 212), including, but not necessarily limited to: the display 204, a mouse, a touchpad, a keyboard, and so on.
The communications interface 212 and/or the processor 208 can be configured to communicate with a variety of different networks, including, but not necessarily limited to: a wide-area cellular telephone network, such as a 3G cellular network, a 4G cellular network, or a global system for mobile communications (GSM) network; a wireless computer communications network, such as a WiFi network (e.g., a wireless local area network (WLAN) operated using IEEE 802.11 network standards); an internet; the Internet; a wide area network (WAN); a local area network (LAN); a personal area network (PAN) (e.g., a wireless personal area network (WPAN) operated using IEEE 802.15 network standards); a public telephone network; an extranet; an intranet; and so on. However, this list is provided by way of example only and is not meant to limit the present disclosure. Further, the communications interface 212 can be configured to communicate with a single network or multiple networks across different access points.
Generally, any of the functions described herein can be implemented using hardware (e.g., fixed logic circuitry such as integrated circuits), software, firmware, manual processing, or a combination thereof. Thus, the blocks discussed in the above disclosure generally represent hardware (e.g., fixed logic circuitry such as integrated circuits), software, firmware, or a combination thereof. In the instance of a hardware configuration, the various blocks discussed in the above disclosure may be implemented as integrated circuits along with other functionality. Such integrated circuits may include all of the functions of a given block, system, or circuit, or a portion of the functions of the block, system, or circuit. Further, elements of the blocks, systems, or circuits may be implemented across multiple integrated circuits. Such integrated circuits may comprise various integrated circuits, including, but not necessarily limited to: a monolithic integrated circuit, a flip chip integrated circuit, a multichip module integrated circuit, and/or a mixed signal integrated circuit. In the instance of a software implementation, the various blocks discussed in the above disclosure represent executable instructions (e.g., program code) that perform specified tasks when executed on a processor. These executable instructions can be stored in one or more tangible computer readable media. In some such instances, the entire system, block, or circuit may be implemented using its software or firmware equivalent. In other instances, one part of a given system, block, or circuit may be implemented in software or firmware, while other parts are implemented in hardware.
Referring now to
Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from determining expected sensor values for a borehole. Features shown in individual embodiments referred to above may be used together in combinations other than those which have been shown and described specifically. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.
This application claims priority to U.S. Provisional Patent Application Ser. No. 62/033647, which was filed on Aug. 6, 2014, and is incorporated herein by reference in its entirety.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2015/042895 | 7/30/2015 | WO | 00 |
| Number | Date | Country | |
|---|---|---|---|
| 62033647 | Aug 2014 | US |
