Patent Application
20100097890
The present invention relates generally to transmission of data within a wellbore and more particularly to methods and apparatuses for obtaining downhole data or measurements while drilling.
In rotary drilling, a rock bit is threaded onto a lower end of a drillstring. The drillstring is lowered and rotated, causing the bit to disintegrate geological formations. The bit cuts a borehole somewhat larger than the drillstring, so an annulus is created between the walls of the borehole and the drill string. Section after section of drill pipe, or other drillstring tool, is added to the drillstring as new depths are reached.
During drilling, a fluid, often called “mud,” is pumped downward through the drill pipe, through the drill bit, and up to the surface through the annulus, carrying cuttings from the borehole bottom to the surface.
It is often useful to detect borehole conditions, drill bit conditions, and drillstring conditions while drilling. However, much of the desired data is not easily collected or retrieved. An ideal method of data retrieval would not slow down or otherwise hinder ordinary drilling operations, or require excessive personnel or the special involvement of the drilling crew. In addition, data retrieved in near real time is generally of greater utility than data retrieved after a prolonged time delay.
Directional drilling is the process of using the drill bit to drill a borehole in a specific direction to achieve some drilling objective. Measurements concerning the drift angle, the azimuth, and tool face orientation all aid in directional drilling. A measurement while drilling system may replace single shot surveys and wire line steering tools, saving time and cutting drilling costs.
Measurement while drilling systems may also yield valuable information about the condition of the drill bit, helping determine when to replace a worn bit, thus avoiding the pulling of bits that are not near their end of life or drilling until a bit fails.
Other valuable information may be gathered by formation evaluation within a measurement while drilling system. Gamma ray logs, formation resistivity logs, and formation pressure measurements are helpful in determining the necessity of liners, reducing the risk of blowouts, allowing the safe use of lower mud weights for more rapid drilling, reducing the risks of lost circulation, and reducing the risks of differential sticking.
Existing measurement while drilling systems are said to improve drilling efficiency. However, problems still remain with the transmission of subsurface data from subsurface sensors to surface monitoring equipment, while drilling operations continue. A variety of data transmission systems have been proposed or attempted, but the search for new and improved systems for data transmission continues. Such attempts and proposals include the transmission of signals through cables in the drill string, or through cables suspended in the bore hole of the drill string; the transmission of signals by electromagnetic waves through the earth; the transmission of signals by acoustic or seismic waves through the drill pipe, the earth, or the mud stream; the transmission of signals by way of releasing chemical or radioactive tracers in the mud stream; the storing of signals in a downhole recorder, with periodic or continuous retrieval; and the transmission of data signals over pressure pulses in the mud stream.
Drilling fluid telemetry in the form of continuous wave and mud pulse telemetry presents a number of challenges. As examples, mud telemetry has a slow data transmission rate, high signal attenuation, difficulty in detecting signals over mud pump noise, maintenance requirements, and the inconvenience of interfacing and matching the data telemetry system with the choice of mud pump, and drill bit.
Electrical telemetry using electrical conductors in the transmission of subsurface data also presents an array of unique problems. One significant difficulty is making a reliable electrical connection at each pipe junction. Communication systems using direct electrical connection between drill pipes have been proposed. In addition, communication systems using inductive coupling and Hall Effect coupling at drill pipe joints have been proposed.
With the ever-increasing need for downhole drilling system dynamic data, a number of “subs” (i.e., a sub-assembly incorporated into the drill string above the drill bit and used to collect data relating to drilling and drillstring parameters) have been designed and installed in drillstrings. For data transmission systems to operate to full advantage, it is desirable that drill string components, such as drill bits and sensor subassemblies, be produced to cooperate therewith. Drillstring components so configured could provide significant amounts of useful data. Unfortunately, such conventional subs are expensive and are configured as dedicated downhole components that must be placed in the drillstring instead of, or in addition to, a simple drill pipe or drill collar.
There is a need for new methods and apparatuses for distributing data processing modules along a drillstring and providing communication between these data processing modules and a remote computer. In addition, there is a need for methods and apparatuses for analyzing dynamic movements of the drillstring.
Embodiments of the present invention include methods and apparatuses for disposing data processing modules in drillstring elements and providing communication between these data processing modules disposed along a drillstring and a remote computer. In addition, embodiments of the present invention include methods and apparatuses for analyzing dynamic movements of the drillstring.
One embodiment of the invention includes a component configured for attachment as part of a drillstring. The component includes a tubular member with a central bore formed therethrough. At a first end of the tubular member is a box-end. At a second end of the tubular member is a pin-end adapted for coupling to a box-end of another downhole tool. The box-end includes a first signal transceiver and the pin-end and includes a second signal transceiver operably coupled to the first signal transceiver and also configured for communication with the first signal transceiver in another component of the drillstring. An end-cap is configured for disposition in the central bore of the pin-end to form an annular chamber between a side of the end-cap and a wall of the central bore of the pin-end when the end-cap is disposed in the central bore of the pin-end. In some embodiments, an electronics module is configured for disposition in the annular chamber and configured to communicate with the second signal transceiver.
Another embodiment of the invention includes a drillstring communication network comprising a plurality of components including downhole tools, subs, joints, drill collars, and other components coupled together. Each component includes a box-end at a first end of the component bearing a first signal transceiver and a pin-end at a second end of the component bearing a second signal transceiver. Some, or all, of the components include an end-cap disposed in a central bore of the pin-end forming an annular chamber between a side of the end-cap and a wall of the central bore of the pin-end. In addition, some, or all, of the components include an electronics module disposed in the annular chamber. The electronics module includes at least one sensor and a communication element operably coupled between the at least one sensor and the second signal transceiver. A remote computer is configured for communicating with the components that include an electronics module. The first signal transceiver of each component and the second signal transceiver of each component are configured for communication therebetween such that the components form a communication link between the communication elements of the components including electronics modules and the remote computer.
Another embodiment of the invention includes a drillstring dynamics analysis network. The network includes a plurality of data processing modules disposed in a plurality of components coupled to form a drillstring. The plurality of data processing modules are operably coupled for communication therebetween and communication with a remote computer. Each data processing module includes a plurality of accelerometers configured for sensing acceleration in a plurality of directions at the data processing module and a communication element operably coupled to the plurality of accelerometers. The communication element is also coupled to at least one other data processing module. Each data processing module is configured to collect accelerometer information at substantially the same time as other data processing modules and transmit the accelerometer information to the at least one communication element in another data processing module, the remote computer, or a combination thereof.
Yet another embodiment of the invention includes a method of communicating information in a drillstring. The method includes communicatively coupling a plurality of components bearing a first transceiver at a box-end and a second transceiver at a pin-end by mechanically coupling the plurality of components to form a drillstring communication network. The method also includes disposing at least one electronics module in an annular chamber of the pin-end of at least one component of the plurality to operably couple the at least one electronics module to the drillstring communication network. At least one physical parameter is sensed near the at least one electronics module and communicated to another electronics module in another component, a remote computer, or a combination thereof.
Yet another embodiment of the invention includes a method of determining dynamics characteristics of a drillstring. The method includes acquiring accelerometer information at a plurality of locations along a drillstring by sampling a plurality of accelerometers disposed in a pin-end of a plurality of drillstring tools operably coupled together to form the drillstring. The method also includes communicating the accelerometer information along the drillstring using communication capabilities of each drillstring tool in the drillstring and processing the accelerometer information from the plurality of locations to determine drillstring dynamics information about the drillstring.
During drilling operations, drilling fluid is circulated from a mud pit 160 through a mud pump 162, through a desurger 164, and through a mud supply line 166 into the swivel 120. The drilling mud (also referred to as drilling fluid) flows through the Kelly joint 122 and into an axial central bore in the drillstring 140. Eventually, it exits through apertures or nozzles, which are located in a drill bit 200, which is connected to the lowermost portion of the drillstring 140 below drill collar section 144. The drilling mud flows back up through an annular space between the outer surface of the drillstring 140 and the inner surface of the borehole 100, to be circulated to the surface where it is returned to the mud pit 160 through a mud return line 168.
A shaker screen (not shown) may be used to separate formation cuttings from the drilling mud before it returns to the mud pit 160. The MWD communication system 146 may utilize a mud pulse telemetry technique to communicate data from a downhole location to the surface while drilling operations take place. To receive data at the surface, a mud pulse transducer 170 is provided in communication with the mud supply line 166. This mud pulse transducer 170 generates electrical signals in response to pressure variations of the drilling mud in the mud supply line 166. These electrical signals are transmitted by a surface conductor 172 to a surface electronic processing system 180, which is conventionally a data processing system with a central processing unit for executing program instructions, and for responding to user commands entered through either a keyboard or a graphical pointing device. The mud pulse telemetry system is provided for communicating data to the surface concerning numerous downhole conditions sensed by well logging and measurement systems that are conventionally located within the MWD communication system 146. Mud pulses that define the data propagated to the surface are produced by equipment conventionally located within the MWD communication system 146. Such equipment typically comprises a pressure pulse generator operating under control of electronics contained in an instrument housing to allow drilling mud to vent through an orifice extending through the drill collar wall. Each time the pressure pulse generator causes such venting, a negative pressure pulse is transmitted to be received by the mud pulse transducer 170. An alternative conventional arrangement generates and transmits positive pressure pulses. As is conventional, the circulating drilling mud also may provide a source of energy for a turbine-driven generator subassembly (not shown) which may be located near a bottom hole assembly (BHA). The turbine-driven generator may generate electrical power for the pressure pulse generator and for various circuits including those circuits that form the operational components of the measurement-while-drilling tools. As an alternative or supplemental source of electrical power, batteries may be provided, particularly as a back up for the turbine-driven generator.
Embodiments of the present invention include methods and apparatuses for disposing data processing modules in drillstring elements and providing communication between these data processing modules disposed along a drillstring and a remote computer. In addition, embodiments of the present invention include methods and apparatuses for analyzing dynamic movements of the drillstring.
As used in this specification, the term “downhole” is intended to have a relatively broad meaning. Downhole includes environments within a wellbore and below the surface, such as, environments encountered when drilling for oil and/or gas, and extraction of other subterranean minerals, as well as when drilling for water and other subsurface liquids, and for geothermal exploration.
The term “component” refers to any pipe, collar, joint, sub or other component having a central bore and used in exploration and/or excavation of a subterranean well. Non-limiting examples of such components include casings, drill pipe, drill collars, drill bit subs, transmission links, reamers, stabilizers, motors, turbines, mud hammers, jars, Kellys, blow-out preventers, and steering subs.
Certain shared functional characteristics are used in order to enable components 190 to join together in series to form a drill string. By way of example and not limitation, the pin-end 210 includes external tapered threads. Conversely, the box-end 230 includes internal tapered threads. The tubular member 220 extends between the box-end 230 and the pin-end 210 and may extend between about thirty and ninety feet in length. The pin-end 210 and the box-end 230 are complementary, such that a pin-end 210 of a first component may be joined to box-end 230 a second component. In this manner, components 190 may be joined together to form a drill string 140 as long as 20,000 feet or more.
A first signal transceiver 250 is illustrated as embedded in a ring around an interior surface 236 of the box-end 230 of the first component 190A. Similarly, a second signal transceiver 255 is embedded in a ring around the outer surface 238 of the pin-end 210 of the second component 190B. When the two components (190A and 190B) are coupled together, the first signal transceiver 250 and the second signal transceiver 255 are disposed opposite each other and substantially close together.
Communication between the first signal transceiver 250 and the second signal transceiver 255 may be implemented in a variety of ways. In
As another non-limiting example, signals may be transmitted between the first signal transceiver 250 and the second signal transceiver 255 by way of Hall Effect coupling as depicted, described, and claimed in U.S. Pat. No. 4,884,071 entitled “Wellbore Tool With Hall Effect Coupling,” which issued on Nov. 28, 1989 to Howard, the disclosure of which is incorporated herein by reference.
An electrical pathway (240A and 240B) is illustrated as a small borehole in the sidewall of the components (190A and 190B) extends between the box-end 230 and the pin-end 210. However, other electrical pathways are possible. As a non-limiting example, the electrical pathway may be configured as a conduit running along the inside surface of the central bore 280 between the box-end 230 and the pin-end 210.
The first signal transceiver 250 and the second signal transceiver 255 within the same component may be coupled for communication as an inter-tool coupling signal inside the electrical pathway 240 in a number of ways. As non-limiting examples, a coaxial cable, twisted pair wires, individual wires, or combinations thereof may be used to couple the first signal transceiver 250 and the second signal transceiver 255 for communication. In addition to signals, the wires or cables may be used for transmitting power to electronics modules along the drillstring. Alternatively, some or all of the electronics modules may include their own independent power source.
With the first signal transceiver 250 and second signal transceiver 255 coupled together in each drillstring tool, and the drillstring tools coupled through inductive coupling, Hall effect coupling, or other suitable communicative coupling, the drillstring tools are all coupled together to form a drillstring communication network.
Each drillstring tool need not include an end-cap 270 or an electronics module (not shown) disposed around the end-cap 270. However, to form a continuous drillstring communication network, each drillstring tool between the surface and the farthest component with a communication element will include a first signal transceiver 250 coupled to a second signal transceiver 255 such that the drillstring forms the continuous network. The communication network may extend partially down the drillstring or may extend all the way to, and including, the drill bit.
A connection pathway 245 extends from the electrical pathway 240 to the central bore 280. This connection pathway 245 enables coupling of the electronics module (not shown in
In the
The end-cap 270 includes a cap bore 276 formed therethrough, such that the drilling mud may flow through the end cap, through the central bore 280 of the pin-end 210 to the other side of the pin-end 210, and then into the body of component 190. In addition, the end-cap 270 includes a first flange 271 including a first sealing ring 272, near the lower end of the end-cap 270, and a second flange 273 including a second sealing ring 274, near the upper end of the end-cap 270.
In the embodiment shown in
As used herein, electronics module 290 generally refers to a physical configuration of a circuit board including electrical components, electronic components, or combinations thereof configured for practicing embodiments of the present invention. Furthermore, as used herein, data processing module generally refers to a functional configuration of elements on the electronics module 290 configured to perform functions according to embodiments of the present invention.
A data processing module may be configured for sampling data in different sampling modes, sampling data at different sampling frequencies, and analyzing data. The data processing module may also be configured to communicate the sampled data, the analyzed data, software, firmware, control data, and combinations thereof to other data processing modules in other components 190, the drill bit, or a surface computer (not shown).
An embodiment of a data processing module 300 is illustrated in
The plurality of accelerometers 340A may include three accelerometers 340A configured in a Cartesian coordinate arrangement. Similarly, the plurality of magnetometers 340M may include three magnetometers 340M configured in a Cartesian coordinate arrangement. While any coordinate system may be defined within the scope of the present invention, one example of a Cartesian coordinate system, shown in
The accelerometers 340A of the
For example, in high motion situations, the first set 340A and the second 340A′ of accelerometers provide a large range of accelerations (i.e., up to 30 g). In lower motion situations, x accelerometers 351 and 351′ provide more precision, of the acceleration at these lower accelerations. As a result, more precise calculations may be performed when deriving dynamic behavior at low accelerations.
Of course, other embodiments may include three coordinates in the second set of accelerometers as well as other configurations and orientations of accelerometers alone or in multiple coordinate sets. With the placement of a second set of accelerometers at a different location on the drill bit, differences between the accelerometer sets may be used to distinguish lateral accelerations from angular accelerations. For example, if the two sets of accelerometers are both placed at the same radius from the rotational center of the component and the component is only rotating about that rotational center, then the two accelerometer sets will experience the same angular rotation. However, the bit may be experiencing more complex behavior, such as, for example, bit whirl, bit wobble, bit walking, and lateral vibration. These behaviors include some type of lateral motion in combination with the angular motion. For example, as illustrated in
Furthermore, if initial conditions are known or estimated, component velocity profiles and component trajectories may be inferred by mathematical integration of the accelerometer data using conventional numerical analysis techniques. As is explained more fully below, acceleration data may be analyzed and used to determine adaptive thresholds to trigger specific events within the data processing module 300. Furthermore, if the acceleration data is integrated to obtain bit velocity profiles or bit trajectories, these additional data sets may be useful for determining additional adaptive thresholds through direct application of the data set or through additional processing, such as, for example, pattern recognition analysis. By way of example, and not limitation, an adaptive threshold may be set based on how far off center a component may traverse before triggering an event of interest within the data processing module 300. For example, if the component trajectory indicates that the component is offset from the center of the borehole by more than one inch, a different algorithm of data collection from the sensors 340 may be invoked.
The magnetometers 340M of the
The data processing module 300 may be configured to provide for recalibration of magnetometers 340M during operation. Recalibration of magnetometers 340M may be necessary to remove magnetic field affects caused by the environment in which the magnetometers 340M reside. For example, measurements taken in a downhole environment may include errors due to a high magnetic field within the downhole formation. Therefore, it may be advantageous to recalibrate the magnetometers 340M prior to taking new measurements in order to take into account the high magnetic field within the formation.
The temperature sensor 340T may be used to gather data relating to the temperature of the component, and the temperature near the accelerometers 340A, magnetometers 340M, and other sensors 340. Temperature data may be useful for calibrating the accelerometers 340A and magnetometers 340M to be more accurate at a variety of temperatures.
Other optional sensors 340 (not shown) may be included as part of the data processing module 300. Some non-limiting examples of sensors 340 that may be useful in the present invention are strain sensors at various locations of the component, temperature sensors at various locations of the component, mud (drilling fluid) pressure sensors to measure mud pressure internal to the component, and borehole pressure sensors to measure hydrostatic pressure external to the component. Sensors 340 may also be implemented to detect mud properties, such as, for example, sensors 340 to detect conductivity or impedance to both alternating current and direct current, sensors 340 to detect changes in mud properties, and sensors 340 to characterize mud properties such as synthetic based mud and water based mud. These optional sensors 340 may include sensors 340 that are integrated with and configured as part of the data processing module 300 or as optional remote sensors 340 placed in other areas of the component 200.
Returning to
The data processing module 300 also includes a communicator 350 (also referred to herein as a communication element 350) for coupling to the second signal transceiver 255 via communication link 247. As stated earlier, the second signal transceiver 255 is coupled to the first signal transceiver 250 by an inter-tool coupling signal 252. In addition, communication between the first signal transceiver 250 in one component and a second signal transceiver 255 in another component occurs via intra-tool coupling signals 254. The communicator 350 may use any suitable communications protocol and communication physical layer, which may depend on the type of inter-tool coupling signal 252 and intra-tool coupling signal 254 used in the component. As non-limiting examples, a wireless communication protocol may include Bluetooth, and 802.11a/b/g protocols. In addition, using the communicator 350, the data processing module 300 may be configured to communicate with a remote processing system (not shown) such as, for example, a computer, a portable computer, or a personal digital assistant (PDA) when the component is not downhole. Thus, the communication link 247 may be used for a variety of functions, such as, for example, to download software and software upgrades, to enable setup of the data processing module 300 by downloading configuration data, and to upload sample data and analysis data. The communicator 350 may also be used to query the data processing module 300 for information related to the component, such as, for example, data processing module serial number, software version, and other long term data that may be stored in the NVRAM.
The processor 320 in the embodiment of
The embodiment of
Software running on the processor 320 may be used to manage battery life intelligence and adaptive usage of power consuming resources to conserve power. The battery life intelligence can track the remaining battery life (i.e., charge remaining on the battery) and use this tracking to manage other processes within the system. By way of example, the battery life estimate may be determined by sampling a voltage from the battery, sampling a current from the battery, tracking a history of sampled voltage, tracking a history of sampled current, and combinations thereof.
The battery life estimate may be used in a number of ways. For example, near the end of battery life, the software may reduce sampling frequency of sensors 340, or may be used to cause the power control bus to begin shutting down voltage signals to various components.
This power management can create a graceful, gradual shutdown. For example, perhaps power to the magnetometers is shut down at a certain point of remaining battery life. At another point of battery life, perhaps the accelerometers are shut down. Near the end of battery life, the battery life intelligence can ensure data integrity by making sure improper data is not gathered or stored due to inadequate voltage at the sensors 340, the processor 320, or the memory 330.
Software modules also may be devoted to memory management with respect to data storage. The amount of data stored may be modified with adaptive sampling and data compression techniques. For example, data may be originally stored in an uncompressed form. Later, when memory space becomes limited, the data may be compressed to free up additional memory space. In addition, data may be assigned priorities such that when memory space becomes limited high priority data is preserved and low priority data may be overwritten.
In some embodiments, the data processing module 300 may include no more than a repeater 355. The repeater 355 may get power from the power supply 310 or from the communication link 247. As the communication signal travels within the component via the inter-tool coupling signal 252 and between components 190 via the intra-tool coupling signal 254, signal attenuation and distortion is likely to occur. Some signal transceivers may have less attenuation than others, but loss and distortion may be a problem, particularly for very long drillstrings. As a result, a repeater 355 can be placed at intervals along the communication signal to amplify and re-condition the signal to be clean and strong for further transmission up the drillstring, down the drillstring, or combination thereof.
In still other embodiments, the data processing module 300 may not include the processor 320 and memory 330. Instead, the communicator 350 may couple directly to the sensors 340 and sample the sensor signals prior to transmission on the communication signal.
As stated earlier, time varying data such as that illustrated in
Trigger event analysis may be as straightforward as a threshold analysis. However, other more detailed analysis may be performed to develop triggers based on component behavior such as component dynamics analysis, formation analysis, and the like.
Some, or all, of the components 190 may include an electronics module 290 coupled to the second signal transceiver 255. As explained earlier, the electronics module 290 may include only a repeater 355. Alternatively, the electronics module 290 may include a variety of components such as processors 320, sensors 340, a repeater 355, and combinations thereof.
The downhole modules may be disposed at regular intervals along the drillstring communication network 400 or may be concentrated at certain areas of the drillstring that are of particular interest. In addition, the drillstring communication network 400 need not traverse the entire drillstring. As a non-limiting example, the drillstring communication network 400 may extend from the remote computer 500 on the surface only down to a stabilizer or motor sub. As another non-limiting example, the drillstring communication network 400 may extend from the drill bit up to an electronics module 290 only part way up the drillstring. In this type of network, some of the electronics modules 290 may include large amounts of memory 330 for storing historical information from the drill bit or other electronics modules 290 in the network.
In addition, motion characteristics may be inferred at locations along the drillstring different from where the electronics modules 290 are located. As a non-limiting example, interpolation of the motion characteristics at two different electronics modules 290 may be used to determine motion characteristics at points along the drillstring between the two electronics modules 290. As another non-limiting example, extrapolation of the motion characteristics at two different electronics modules 290 may be used to determine motion characteristics at points along the drillstring that are outside the two electronics modules 290.
To analyze the dynamic movement characteristics of the drillstring as a whole, the acceleration measurements, velocity determinations, and displacement determinations at each of the data processing module 300 locations must be synchronized with respect to each other so that the data at each location can be correlated to the same time.
Time synchronization of the distributed data-acquisition/sensor packages may be accomplished in a pair-wise fashion using an algorithm used for networks, e.g., TPSN (time synchronization for sensor networks) or TDMA (time division multiple access). In the case of TPSN, the objective is to discover a propagation time and a clock drift between two sensors. Propagation time and clock drift may be represented as:
Propagation=(deltaT1-2+deltaT2-1)/2
clock drift=(deltaT1-2−deltaT2-1)/2
Where deltaT1-2 is the total transit time (propagation time+clock drift) from unit 1 to unit 2 and deltaT2-1 is the total transit time from unit 2 to unit 1.
In addition, this pair-wise check may be performed periodically during the run to maintain synchronization, which may vary due to clock drift.
In the communication network described herein, there may be significant latency between when a signal starts at one point of the drillstring and when it reaches the farthest data processing module 300. This latency may be caused by the intra-tool coupling signal 254 links, repeaters 355, and even the inter-tool coupling signal 252 distances that must be traveled. As a result, merely sending a start time down the communication signal as a synchronization point will not be effective because it may be difficult, or impossible to determine the latency at each point where a data processing module 300 resides.
The last data processing module DN receives the forward synchronization signal and responds by sending a return synchronization signal tDNB back up the drillstring. At a time delay later, the return synchronization signal tD(N−1)B arrives at data processing module D(N−1). At a time delay later, the return synchronization signal tD2B arrives at data processing module D2. At a time delay later, the return synchronization signal tD1B arrives at data processing module D1. At a time delay later, the return synchronization signal tSB arrives at the remote computer 500.
Each data processing module along the drillstring may begin collecting accelerometer data when it receives its forward synchronization signal tXA and for a predetermined time period thereafter. A synchronization time tSYNCH may be determined by the remote computer 500 based on the forward synchronization signal tSA and the return synchronization signal tSB. This determination may be as simple as one-half the difference between the forward synchronization signal tSA and the return synchronization signal tSB. However, in some cases, latency for signals in the forward direction may be different from latency for signals in the return direction. This difference may be taken into account in the determination of the synchronization time tSYNCH.
Each of the data processing modules 300 may determine the synchronization time tSYNCH in a similar manner based on its forward synchronization signal tXA and its return synchronization signal tXB. With the synchronization time tSYNCH determined, the data processing module 300 may delete the accelerometer data collected between its forward synchronization signal tXA and the synchronization time tSYNCH. Thus, the accelerometer data at each data processing module 300 begins at the same time. With this fixed starting point at each of the data processing modules 200, correlated velocity and displacement determinations may be made by each data processing module 300. The information for acceleration, velocity, and displacement may be transferred from each data processing module 300 to the remote computer 500 for further processing, such as, for example, harmonic vibration analysis.
In another processing model, each data processing module 300 may send its acceleration information to the remote computer 500 from its forward synchronization signal tXA time, along with the time difference between the forward synchronization signal tXA and the return synchronization signal tXB. The remote computer 500 can then strip off accelerometer information for each data processing module 300 between the forward synchronization signal tXA and the synchronization time tSYNCH. The remote computer 500 can then determine correlated velocity and displacement information for each data processing module 300 and perform harmonic vibration analysis on the drillstring.
This synchronization time tSYNCH process has been described relative to a remote computer 500 on the surface generating the initial forward synchronization signal tSA and receiving the final return synchronization signal tSB. However, the forward synchronization signal tXA may be initiated by one of the data processing modules 300. In addition, the forward direction may be defined as from the drill bit toward the surface, rather than from the surface toward the drill bit. Thus, if the entire drillstring is participating in the communication network, the drill bit may initiate the forward synchronization signal tXA and the remote computer 500 may generate the return synchronization signal tXB.
As another example of a synchronization mechanism, a model may be developed of the drill string relative to characteristics of the various drillstring components. Some non-limiting examples of characteristics that may be modeled are length of the components, material, torsional stiffness, axial stiffness and lateral stiffness.
In addition, a synchronization signal may be propagated along the drill string using methods other than an electronic signal. As a non-limiting example, the synchronization signal may be a mud pulse that is detectable by each of the electronics modules 290. As another non-limiting example, the synchronization signal may be an acceleration event that is propagated along the drillstring. Non-limiting examples of such acceleration events are a sonic pulse that is directed along the drillstring or a drilling event (e.g., the drill bit hitting the bottom of the hole) that will propagate along the drillstring.
Using the model of the drillstring, propagation times of these synchronization signals may be determined quite accurately such that each electronics module 290 may be able to determine a synchronization time in response to an arrival time of the synchronization pulse and an analysis of the drillstring model.
While the present invention has been described herein with respect to certain preferred embodiments, those of ordinary skill in the art will recognize and appreciate that it is not so limited. Rather, many additions, deletions, and modifications to the preferred embodiments may be made without departing from the scope of the invention as hereinafter claimed. In addition, features from one embodiment may be combined with features of another embodiment while still being encompassed within the scope of the invention as contemplated by the inventors.
