Surface real-time processing of downhole data

A method and apparatus for controlling oil well drilling equipment is disclosed. One or more sensors are distributed in the oil well drilling equipment. Each sensor produces a signal. A surface processor coupled to the one or more sensors via a high speed communications medium receives the signals from the one or more sensors via the high speed communications medium. The surface processor is situated on or near the earth's surface. The surface processor includes a program to process the received signals and to produce one or more control signals. The system includes one or more controllable elements distributed in the oil well drilling equipment. The one or more controllable elements respond to the one or more control signals.

BACKGROUND

As oil well drilling becomes more and more complex, the importance of maintaining control over as much of the drilling equipment as possible increases in importance.

DETAILED DESCRIPTION

As shown inFIG. 1, oil well drilling equipment100(simplified for ease of understanding) includes a derrick105, derrick floor110, draw works115(schematically represented by the drilling line and the traveling block), hook120, swivel125, kelly joint130, rotary table135, drill string140, drill collar145, LWD tool or tools150, and drill bit155. Mud is injected into the swivel by a mud supply line (not shown). The mud travels through the kelly joint130, drill string140, drill collars145, and LWD tool(s)150, and exits through jets or nozzles in the drill bit155. The mud then flows up the annulus between the drill string and the wall of the borehole160. A mud return line165returns mud from the borehole160and circulates it to a mud pit (not shown) and back to the mud supply line (not shown). The combination of the drill collar145, LWD tool(s)150, and drill bit155is known as the bottomhole assembly (or “BHA”). In one embodiment of the invention, the drill string is comprised of all the tubular elements from the earth's surface to the bit, inclusive of the BHA elements. In rotary drilling the rotary table135may provide rotation to the drill string, or alternatively the drill string may be rotated via a top drive assembly. The term “couple” or “couples” used herein is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect electrical connection via other devices and connections.

A number of downhole sensor modules and downhole controllable elements modules170are distributed along the drill string140, with the distribution depending on the type of sensor or type of downhole controllable element. Other downhole sensor modules and downhole controllable element modules175are located in the drill collar145or the LWD tools. Still other downhole sensor modules and downhole controllable element modules175are located in the bit180. The downhole sensors incorporated in the downhole sensor modules, as discussed below, include acoustic sensors, magnetic sensors, gravitational field sensors, gyroscopes, calipers, electrodes, gamma ray detectors, density sensors, neutron sensors, dipmeters, resistivity sensors, imaging sensors, weight on bit, torque on bit, bending moment at bit, vibration sensors, rotation sensors, rate of penetration sensors (or WOB, TOB, BOB, vibration sensors, rotation sensors or rate of penetration sensors distributed along the drillstring), and other sensors useful in well logging and well drilling. The downhole controllable elements incorporated in the downhole controllable element modules, as discussed below, include transducers, such as acoustic transducers, or other forms of transmitters, such as x-ray sources, gamma ray sources, and neutron sources, and actuators, such as valves, ports, brakes, clutches, thrusters, bumper subs, extendable stabilizers, extendable rollers, extendible feet, etc. To be clear, even sensor modules that do not incorporate an active source may still for purposes herein be considered to be controllable elements. Preferred embodiments of many of the sensors discussed above and throughout may include controllable acquisition attributes such as filter parameters, dynamic range, amplification, attenuation, resolution, time window or data point count for acquisition, data rate for acquisition, averaging, or synchronicity of data acquisition with related parameter (e.g. azimuth). Control and varying of such parameters improves the quality of the individual measurements, and allows for a far richer data set for improved interpretations. Additionally, the manner in which any particular sensor module communicates may be controllable. A particular sensor module's data rate, resolution, order, priority, or other parameter of communication over the communication media (discussed below) may be deliberately controlled, in which case that sensor too is considered a controlled element for purposes herein.

The sensor modules and downhole controllable element modules communicate with a surface real-time processor185through communications media190. The communications media can be a wire, a cable, a waveguide, a fiber, or any other media that allows high data rates. Communications over the communications media190can be in the form of network communications, using, for example Ethernet, with each of the sensor modules and downhole controllable element modules being addressable individually or in groups. Alternatively, communications can be point-to-point. Whatever form it takes, the communications media190provides high speed data communication between the devices in the borehole160and the one or more surface real-time processors. Preferably, the communication and addressing protocols are of a type that is not computationally intensive, so as to drive a relatively minimal hardware requirement dedicated downhole to the communication and addressing function, as discussed further below.

The surface real-time processor185may have data communication, via communications media190or via another route, with surface sensor modules and surface controllable element modules195. The surface sensors, which are incorporated in the surface sensor modules as discussed below, may include, for example, hook load (for weight-on-bit) sensors and rotation speed sensors. The surface controllable elements, which are incorporated in the surface controllable element modules, as discussed below, include, for example, controls for the draw works115and the rotary table135.

The surface real-time processor185may also include a terminal197, which may have capabilities ranging from those of a dumb terminal to those of a workstation. The terminal197allows a user to interact with the surface real-time processor185. The terminal197may be local to the surface real-time processor185or it may be remotely located and in communication with the surface real-time processor185via telephone, a cellular network, a satellite, the Internet, another network, or any combination of these.

The oil well drilling equipment may also include a power source198. Power source198is shown inFIG. 1as being ambiguously located to convey the idea that the power source can be (a) located at the surface with the surface processor; (b) located in the borehole; or (c) distributed along the drill string or a combination of those configurations. If it is on the surface, the power source may be the local power grid, a generator or a battery. If it is in the borehole the power source may be an alternator, which may be used to convert the energy in the mud flowing through the drill string into electrical energy, or it may be one or more batteries or other energy storage devices. Power may be generated downhole using a turbine driven by mud flow or by pressure differential being used, for example, to set a spring.

As illustrated by the logical schematic of the system inFIG. 2, the high speed communications media190provides high speed communications between the surface sensors and controllable elements195, and/or the downhole sensor modules and controllable element modules170,175,180, and the surface real-time processor185. In some cases, the communications from one downhole sensor module or controllable element module215may be relayed through another downhole sensor module or downhole controllable element module220. The link between the two downhole sensor modules or downhole controllable element modules215and220may be part of the communications media190. Similarly, communications from one surface sensor module or surface controllable element module205may be relayed through another surface sensor module or surface controllable element module210. The link between the two surface sensor modules or surface controllable element modules205and210may be part of the communications media190.

The high speed communications media190may be a single communications path or it may be more than one. For example, one communications path, e.g. cabling, may connect the surface sensors and controllable elements195to the surface real-time processor185. Another, e.g. wired pipe, may connect the downhole sensors and controllable elements170,175,180to the surface real-time processor185.

The communications media190is labeled “high speed” onFIG. 2. This designation indicates that the communications media190operates at a speed sufficient to allow real-time control, e.g., at wire-speed, through the surface real time processor185, of the surface controllable elements and the downhole controllable elements based on signals from the surface sensors and the surface controllable elements. Generally, the high speed communications media190provides communications at a rate greater than that provided by mud telemetry, acoustic telemetry, or electromagnetic (EM) telemetry. In some example systems, the high speed communications are provided by wired pipe, which at the time of filing was capable of transmitting data at a rate of up to approximately 1 megabit/second. Considerably higher data rates are expected in the future and fall within the scope of this disclosure and the appended claims. It is recognized that mechanical connections between segments of the communications path, addressing and other overhead functions, and other practical implementation factors may reduce the actual data rate attained substantially from these megabit ideals. So long as the effective data transmission rates are substantially higher than those available through mud, acoustic, and EM telemetry (i.e. substantially above 10-100 Hz), and sufficient for the new measurement and control purposes contemplated herein, they are deemed for purposes of this application to be “high speed”. For many of the measurement and control purposes contemplated herein, a 1000 Hz data rate would fulfill these requirement. Likewise, the term “real time” as used herein to describe various processes is intended to have an operational and contextual definition tied to the particular processes, such process steps being sufficiently timely for facilitating the particular new measurement or control process herein focused upon. For example, in the context of drill pipe being rotated at 120 revolutions per minute (RPM), and an improved measurement process providing for azimuthal resolution of 5 degrees, a “real time” series of process steps would occur sufficiently timely in context of the 1/144 of a second duration for that 5 degrees of rotation.

In one embodiment of the invention, the outputs from the sensors are transmitted to the surface real-time processor in a particular sequence, in other embodiments of the invention the transmission of the outputs of the sensors to the surface real-time processor is in response to a query addressed to a particular sensor by surface real-time processor185. Similarly, outputs to the controllable elements modules may be sequenced or individually addressed. In one embodiment of the invention, communications between the sensors and the surface real-time processor is via the Transmission Control Protocol (TCP), the Transmission Control Protocol/Internet Protocol (TCP/IP), or the User Datagram Protocol (UDP). By using one or more of these protocols, the surface real-time processor may be locally disposed at the surface of the well bore or remotely disposed at any location on the earth's surface.

The power source198is illustrated inFIG. 2in several ways, designated by references198A . . . E. For example, power source198A may be on the surface with, and may provide power to, the surface real-time processor185. In addition, the power source198A may provide power from the surface to other oil well drilling equipment located at or near the surface or throughout the borehole. The power could be provided from this surface via an electric line or via a high power fiber optic cable with power converters at the locations where power is to be delivered.

Power source198B may be co-located with and provide power to a single surface sensor or controllable element module185. Alternatively, power source198C may be co-located with one surface sensor and controllable element module185and provide power for more than one surface sensor or controllable element module185.

Similarly, power source198D may be co-located with and provide power to a single downhole sensor or controllable element module185. Alternatively, power source198E may be co-located with one downhole sensor and controllable element module185and provide power for more than one downhole sensor or controllable element module185.

A general system for real-time control of downhole and surface logging while drilling operations using data collected from downhole sensors and surface sensors, illustrated inFIG. 3, includes downhole sensor module(s)305and surface sensor module(s)310. Raw data is collected from the downhole sensor module(s)305and sent to the surface (block315) where it may be stored in a surface raw data store320. Similarly, raw data is collected from the surface sensor module(s)310and may be stored in the surface raw data store320. Raw data store320may be transient memory such as random access memory (RAM), or persistent memory, e.g., read only memory (ROM), or magnetic or optical storage media.

Raw data from the surface raw data store320is then processed in real time (block325) and the processed data may be stored in a surface processed data store330. The processed data is used to generate control commands (block335). In some cases, the system provides displays to a user340through, for example, terminal197, who can influence the generation of the control commands. The control commands are used to control downhole controllable elements345and/or surface controllable elements350. In one embodiment of the invention the control commands are automatically generated, e.g., by real time processor185, during or after processing of the raw data and the control commands are used to control the downhole controllable elements345and/or surface controllable elements350.

In many cases, the control commands produce changes or otherwise influence what is detected by the downhole sensors and/or the surface sensors, and consequently the signals that they produce. This control loop from the sensors through the real-time processor to the controllable elements and back to the sensors allows intelligent control of logging while drilling operations. In many cases, as described below, proper operation of the control loops requires a high speed communication media and a real-time surface processor.

Generally, the high-speed communications media190permits data to be transmitted to the surface where it can be processed by the surface real-time processor185. The surface real-time processor185, in turn, may produce commands that can be transmitted at least to the downhole sensors and downhole controllable elements to affect the operation of the drilling equipment. Surface real-time processor185may be any of a wide variety of general purpose processors or microprocessors (such as the Pentium® family of processors manufactured by Intel® Corporation), a special purpose processor, a Reduced Instruction Set Computer (RISC) processor, or even a specifically programmed logic device. The real-time processor may comprise a single microprocessor based computer, or a more powerful machine with multiple multiprocessors, or may comprise multiple processor elements networked together, any or all of which may be local or remote to the location of the drilling operation.

Moving the processing to the surface and eliminating much, if not all, of the downhole processing makes it possible in some cases to reduce the diameter of the drill string producing a smaller diameter well bore than would otherwise be reasonable. This allows a given suite of downhole sensors (and their associated tools or other vehicles) to be used in a wider variety of applications and markets.

Further, locating much, if not all, of the processing at the surface reduces the number of temperature-sensitive components that operate in the severe environment encountered as a well is being drilled. Few components are available which operate at high temperatures (above about 200° C.) and design and testing of these components is very expensive. Hence, it is desirable to use as few high temperature components as possible.

Further, locating much, if not all, of the processing at the surface improves the reliability of the downhole tool design because there are fewer downhole parts. Further, such designs allow a few common elements to be incorporated in an array of sensors. This higher volume use of a few components results in a cost reduction in these components.

An example sensor module400, illustrated inFIG. 4, includes, at a minimum, a sensor device or devices405and an interface to the communications medium410(which is described in more detail with respect toFIGS. 6 and 7). In most cases, the output of each sensor device405is an analog signal and generally the interface to the communications media410is digital. An analog to digital converter (ADC)415is provided to make that conversion. If the sensor device405produces a digital output or if the interface to the communications media410can communicate an analog signal through the communications media190, the ADC415is not necessary.

A microcontroller420may also be included. If it is included, the microcontroller420manages some or all of the other devices in the example sensor module400. For example, if the sensor device405has one or more controllable parameters, such as frequency response or sensitivity, the microcontroller420may be programmed to control those parameters. The control may be independent, based on programming included in memory attached to the microcontroller420, or the control may be provided remotely through the high-speed communications media190and the interface to the communications media410. Alternatively, if a microcontroller420is not present, the same types of controls may be provided through the high-speed communications media190and the interface to communications media410. The microcontroller, if included, may additionally handle the particular sensor or other device's addressing and interface to the high-speed communications media. Microcontrollers such as members of the PICmicro® family of microcontrollers from Microchip Technology Inc. with a limited (as compared to the real-time processor described earlier) but adequate capability for the limited downhole control purposes set out herein are capable of high efficiency packaging and high temperature operation.

The sensor module400may also include an azimuth sensor425, which produces an output related to the azimuthal orientation of the sensor module400, which may be related to the orientation of the drill string if the sensor modules are coupled to the drill string. Data from the azimuth sensor425is compiled by the microcontroller420, if one is present, and sent to the surface through the interface to the communications media410and the high-speed communications media190. Data from the azimuth sensor425may need to be digitized before it can be presented to the microcontroller420. If so, one or more additional ADCs (not shown) would be included for that purpose. At the surface, the surface processor185combines the azimuthal information with other information related to the depth of the sensor module400to identify the location of the sensor module400in the earth. As that information is compiled, the surface processor (or some other processor) can compile a good map of the particular borehole parameters measured by sensor module400.

The sensor module400may also include a gyroscope430, which may provide true geographic orientation information rather than Just the magnetic orientation information provided by the azimuth sensor425. Alternately, one or more gyroscopes or magnetometers disposed along the drill pipe may provide the angular velocity of the drill pipe at each location of the gyroscope. The information from the gyroscope is handled in the same manner as the azimuthal information from the azimuth sensor, as described above. The sensor module400may also include one or more accelerometers. These are used to compensate the gyro for motion and to provide an indication of the inclination and gravity tool face of the survey tool.

An example controllable element module500, shown inFIG. 5, includes, at a minimum, an actuator505and/or a transmitter device or devices510and an interface to the communications media515. The actuator505is one of the actuators described above and may be activated through application of a signal from, for example, a microcontroller520, which is similar in function to the microcontroller420shown inFIG. 4. The transmitter device is a device that transmits a form of energy in response to the application of an analog signal. An example of a transmitter device is a piezoelectric acoustic transmitter that converts an analog electric signal into acoustic energy by deforming a piezoelectric crystal. In the example controllable element module500illustrated inFIG. 5, the microcontroller520generates the signal that is to drive the transmitter device510. Generally, the microcontroller generates a digital signal and the transmitter device is driven by an analog signal. In those instances, a digital-to-analog converter (“DAC”)525is necessary to convert the digital signal output of the microcontroller520to the analog signal to drive the transmitter device510.

The example controllable element module500may include an azimuth sensor530or a gyroscope535, which are similar to those described above in the description of the sensor module400, or it may include an inclination sensor, a tool face sensor, a vibration sensor or a standoff sensor.

The interface to the communications media415,515can take a variety of forms. In general, the interface to the communications media415,515is a simple communication device and protocol built from, for example, (a) discrete components with high temperature tolerances or (b) from programmable logic devices (PLDs) with high temperature tolerances, or (c) the microcontroller with associated limited high temperature memory module discussed earlier with high temperature tolerances.

The interface to the communications media415,515may take the form illustrated inFIG. 6. In the example shown inFIG. 6, the interface to the communications media415,515includes a communications media transmitter605which receives digital information from within the sensor module400or the controllable element module500and applies it to a bus610. A communications receiver615receives digital information from the bus and provides it to the remainder of the sensor module400or the controllable element module500. A communications media arbitrator620arbitrates access to the bus. Thus, the arrangement inFIG. 6can be accomplished with a variety of conventional networking schemes, including Ethernet, and other networking schemes that include a communications arbitrator620.

Preferably, however, the interface to communications media415,515is a simple device, as illustrated inFIG. 7. It includes a Manchester encoder705and a Manchester decoder710. The Manchester encoder accepts digital information from the sensor module400or the controllable element module500and applies it to a bus715. The Manchester decoder710takes the digital data from the bus715and provides it to the sensor module400or controllable element module500. The bus715can be arranged such that it is connected to all sensor modules400and all controllable element modules500, in which case a collision avoidance technique would be applied. For example, the data from the various sensor modules400and controllable element modules500could be multiplexed, using a time division multiplex scheme or a frequency division multiplex scheme. Alternatively, collisions could be allowed and sorted out on the surface using various filtering techniques. Other simple communications protocols that could be applied to the interface to the communications media415,515include the Discrete Multitone protocol and the VDSL (Very High Rate Digital Subscriber Line) CDMA (Code Division Multiple Access) protocol.

Alternatively, each sensor module400and each controllable element module500could have a dedicated connection to the surface, using for example a single conductor of a multi-conductor cable or a single strand of a multi-stranded optical cable.

The overall approach to the sensor module400and the controllable element module500is to simplify the downhole processing and communication elements and to move the complex processing and electronics to the surface. In one embodiment of the invention, the complex processing is done at a location remotely disposed from the high temperatures of the drilling environment, e.g., nearer the surface end of the drill string. We use the term “surface processor” herein to mean the real time processor as defined earlier. However, while locating the real-time processor fully at surface may be preferred in many circumstances, there may be advantages in certain applications to locating part or all of the real-time processor near but not necessarily at surface, or on or near the sea bed, but in all cases remote from the high temperature drilling environment.

The apparatus and method illustrated inFIGS. 2 and 3can be applied to a large number of logging while drilling or measurement while drilling applications. For example, as illustrated inFIG. 8, the apparatus and method can be applied to sonic logging while drilling. For example, as illustrated inFIG. 8, sonic sensor modules805A . . . M emit acoustic energy and sense acoustic energy from the formations around the drill string where the sensor modules are located, although in some applications the sonic sensor modules805A . . . M do not emit energy. In those cases, the sonic energy detected is generated by another source, such as, for example, the action of the bit in the borehole. The sensor modules produce raw data. The raw data is sent to the surface (block315) where it is stored in the surface raw data store (block320). The raw data is processed to determine wave speed in the formations surrounding the drill string where the sonic sensor modules805A . . . M are located (block810).

Real-time measurement of compressional wave speed is usually possible with downhole hardware, but real-time measurement of shear wave speed or measurement of other downhole modes of sonic energy propagation requires significant analysis. By moving the raw data to the surface in real time, it is possible to apply the significant power provided by the surface real-time processor185. The resulting processed data is stored in the surface process data store330. In some cases, real-time analysis would indicate that it is desirable to change the operating frequency of the sensor and the transmitter in order to get a more accurate or a less ambiguous measurement. To accomplish this, the data in the surface processed data store330is processed to determine if the frequency or frequencies being used by the sonic transmitters should be changed (block815). This processing may produce commands that are provided to sonic transmitter modules820, if they are being used to generate the sonic energy, and to the sonic sensor modules805A . . . M. Further, the user340may be provided with displays which illustrate operation of the sonic logging while drilling system. The system may allow the user to provide commands to modify that operation.

The same apparatus and methods can be applied to look-ahead/look-around sensors. Look-ahead sensors are intended to detect a formation property or a change in a formation property ahead of the bit, ideally tens of feet or more ahead of the bit. This information is important for drilling decisions, for example recognizing an upcoming seismic horizon and possible highly pressured zone in time to take precautionary measures (e.g. weighting up the mud) before the bit encounters such zone. Look-around sensors take this concept to the next level, not just detecting properties straight ahead of the bit, but also tens of feet to the sides (i.e. radially). The look-around concept may be especially applicable to steering through horizontal zones where the properties above and below may be even more important than that ahead of the bit, e.g. in geophysical steering through particular fault blocks and other structures. Look-around sensors are most useful when they have azimuthal capability, which means that they produce very large volumes of data. Because of non-uniqueness of interpretation of these data, they should be interpreted at the surface, with assistance from an expert. Generally, two types of technology have been used for such measurements (with various combinations of these two technologies, such as in electroseismics): (1) acoustic look-ahead/look-around; and (2) electromagnetic look-ahead/look-around (including borehole radar sensors). Information from look-ahead/look-around sensors905A . . . M is gathered and converted into raw data which is sent to the surface (block315). The raw data is stored in the surface raw data store (block320) and interpreted (block910). The processed data is stored in the surface process data store (block330) and a process to control, for example, the frequency of the look-ahead/look-around sensors905A . . . M (block915) produces the necessary command to accomplish that function. As before, the system provides the user340with displays and accepts commands from the user.

The interpretation of data process (block910), which is performed by the surface real-time processor185, allows interpretation and processing to identify reflections and mode conversions of acoustic and electromagnetic waves. Surface processing allows dynamic control of the look-ahead/look-around sensors and the associated transmitters. If the look-ahead/look-around sensor905A . . . M is an acoustic device, each channel may be sampled at a frequency on the order of 5,000 samples per second. Suppose there are 14 such channels, and each channel is digitized to 16 bits (a very conservative value). Then the data rate for the acoustic signals alone is 140K bytes per second. Most of the proposed electromagnetic systems operate a bit differently, but would achieve similar effective sampling rates, while combined systems (EM+acoustic) would require even higher data rates. For some implementations, these estimates may be low by more than an order of magnitude. Enough data must be acquired to unambiguously identify the direction and relative depth of all reflectors. Having the processing at surface rather than downhole enables this raw processing, the modifying of the data acquisition parameters as required, but also allows the marriage of these downhole data to surface data and interpretations already available, such as a surface seismics-based earth model. With such a marriage of data sources at surface better interpretations can be made.

Similarly, as illustrated inFIG. 10, magnetic resonance while drilling can be accomplished using a similar arrangement of sensors and processing. Magnetic resonance sensors1005A . . . M generate raw data which is digitized and transmitted to the surface (block320). Because of the high data rate available from the high speed communications media190, the raw data transmitted to the surface can represent the full received wave form rather than an abbreviated wave form. The raw data is stored in a surface raw data store (block320). The raw data is analyzed (block1010), which is possible with greater precision than is conventional because raw data representing the entire wave is received, and the processed data is stored in a surface processed data store (block330). The data stored in the surface processed data store at330is further processed to determine how best to adjust the transmitted waves (block1015). The process for adjusting transmitted waves (block1015) provides displays to a user340and receives commands from the user that are used to modify the process for adjusting transmitted waves (block1015). The process for adjusting the transmitted waves (block1015) produces commands that are transmitted to the magnetic resonance sensors1005A . . . M, which modify the performance characteristics of the magnetic resonance sensors.

The same apparatus and method can be used with drilling mechanics sensors, as illustrated inFIG. 11. Drilling mechanics sensors1105A . . . M are located in various locations in the drilling equipment, including in the drilling rig, the drill string and the bottom hole assembly (“BHA”). Raw data is gathered from the drilling mechanics sensors1105A . . . M and sent to the surface (block315). The raw data is stored in the surface raw data store (block320). The raw data in the surface raw data store is analyzed (block1110) to produce processed data, which is stored in a surface processed data store (block330). The data in the surface processed data store (block330) is further processed to determine adjustments that should be made to the drilling equipment (block1115). The process to adjust the drilling equipment (block1115) provides displays to a user340who can then provide commands to the process for adjusting drilling equipment (block1115). The process to adjust drilling equipment (block1115) provides commands that are used to adjust downhole controllable drilling equipment1120and surface controllable drilling equipment1125.

The drilling mechanics sensors may be accelerometers, strain gauges, pressure transducers, and magnetometers and they may be located at various locations along the drill string. Providing the data from these downhole drilling mechanics sensors to the surface real-time processor185allows drilling dynamics at any desired point along the drill string to be monitored and controlled in real time. This continuous monitoring allows drilling parameters to be adjusted to optimize the drilling process and/or to reduce wear on downhole equipment.

The downhole drilling mechanics sensors may also include one or more standoff transducers, which are typically high frequency (250 KHz to one MHz) acoustic pingers. Typically, the standoff transducers both transmit and receive an acoustic signal. The time interval from the transmission to the reception of the acoustic signal is indicative of standoff. Interpretation of data from the standoff transducers can be ambiguous due to borehole irregularities, interference from cuttings, and a phenomenon known as “cycle skipping,” in which destructive interference prevents a return from an acoustic emission from being detected. Emissions from subsequent cycles are detected instead, resulting in erroneous time of flight measurements, and hence erroneous standoff measurements. Transmitting the data from the downhole drilling mechanics sensors to the surface allows a more complete analysis of the data to reduce the effect of cycle skipping and other anomalies of such processing.

The downhole drilling mechanics sensors may also include borehole imaging devices, which may be acoustic, electromagnetic (resistive and/or dielectric) or which may image with neutrons or gamma rays. An improved interpretation of this data is made in conjunction with drill string dynamics sensors and borehole standoff sensors. Using such data, the images can be sharpened by compensating for standoff, mud density, and other drilling parameters detected by the downhole drilling mechanics sensors and other sensors. The resulting sharpened data can be used to make improved estimates of formation depth.

Thus, borehole images and the data from standoff sensors are not only useful in their own right in formation evaluation, they may also be useful in processing the data from other drilling mechanics sensors.

The same apparatus and method can be used with downhole surveying instruments, as illustrated inFIG. 12. Raw data from downhole surveying instruments1205A . . . M is sent to the surface (block315) and stored in a surface raw data store (block320). The raw data is then used to determine the locations of the various downhole surveying instruments1205A . . . M (block1210). The processed data is stored in surface processed data store (block330). That data is used by a process to adjust drilling equipment (block1215), with the adjustments potentially affecting the drilling trajectory. The process to adjust drilling equipment may produce displays which are provided to a user340. The user340can enter commands which are accepted by the process for adjusting drilling equipment and used in its processing. The process for adjusting drilling equipment (block1215) produces commands that are used to adjust downhole controllable drilling equipment1220and surface controllable drilling equipment1225.

The use of such downhole surveying instruments and real time surface data processing improves the precision with which downhole positions can be measured. The positional accuracy achievable with even a perfect survey tool (i.e., one that produces errorless measurements) is a function of the spatial frequency at which surveys are taken. Even with a perfect survey tool, the resulting surveys will contain errors unless the surveys are taken continuously and interpreted continuously. A practical compromise to continuous surveying is suggested by the realization that the spatial frequency of surveys taken more frequently than about once per centimeter has little impact on survey accuracy. The high-speed communications media190and the surface real-time processor185provides very high data rate telemetry and allows surveys to be taken and interpreted at this rate. Further, other types of survey instruments can be used when very high data rate telemetry is available. In particular, several types of gyroscopes, as discussed above with respect toFIGS. 4 and 5, could be used downhole.

The same apparatus and method can be applied in real-time pressure measurements, as illustrated inFIG. 13. Raw data from pressure sensors1305A . . . M is sent to the surface (block315) where it is stored in the surface raw data store (block320). The raw data is processed to identify pressure characteristics at, for example, a particular point along the drill string or in the borehole or to characterize the pressure distribution all along the drill string and throughout the borehole (block310). Processed data regarding these pressure parameters is stored in the surface processed data store (block330). The data stored in the surface processed data store (block330) is processed in order to react to the pressure parameters (block1315). Displays are provided to a user340who can then issue commands to effect how the system is going to respond to the pressure parameters. The process for reacting to pressure parameters (block1315) produces commands for downhole controllable drilling equipment1320and surface controllable drilling equipment1325.

This virtually instantaneous transfer of real-time pressure measurements, possibly from numerous locations along the drill string, makes it possible to make a number of real-time measurements of borehole and drilling equipment characteristics, such as leakoff tests, real-time determination of circulating density, and other parameters determined from pressure measurements.

The same apparatus and method can be used to provide real-time joint inversion of data from multiple sensors, as illustrated inFIG. 14. Raw data from various types of downhole sensors1405A . . . M, which can include any of the above-described sensors or other sensors that are used in oil well drilling and logging, is gathered and sent to the surface (block315) where it is stored in a surface raw data store (block320). The raw data from the surface raw data store (block320) is processed to jointly invert the data as described below (block1410). Note that joint inversion is just one example of the type of processing that could be performed on the data. Other analytical, computational or signal processing may be applied to the data as well. The resulting processed data is stored in the surface processed data store (block330). That data is further processed to adjust a well model (block1415). The process to adjust the well model provides displays to a user340and receives commands from the user340that affect how the well model is adjusted. The process for adjusting the well model (block1415) produces modifications which are applied to well model1420. The well model1420may be used in planning drilling and subsequent operations, and may be used in adjusting the plan for the drilling and subsequent operations currently underway or imminent.

(x1x2⋯⋯xN)=(g1⁡(v1,v2,…⁢,vN)g2⁡(v1,v2,…⁢,vN)⋯⋯gN⁡(v1,v2,…⁢,vN))so⁢⁢that⁢⁢(v1,v2,…⁢,vN)=gk⁡(fk⁡(v1,v2,…⁢,vN))⁢⁢for⁢⁢1≤k≤N
is also called joint inversion. This process is sometimes carried out algebraically, sometimes numerically, and sometimes using Jacobian transformations, and more generally with any combination of these techniques.

More general types of inversions are indeed possible, where

but in this case, there is no unique set of functions g1, g2, . . . , gM.

Such joint inversions of data collected from different types of sensors provides an ability to perform comprehensive analysis of formation parameters. Traditionally, a separate interpretation is made of data from each sensor in an MWD or LWD drill string. While this is useful, for a full suite of measurements and for a full suite of sensors, it is difficult to make measurements with adequate frequency to support a comprehensive analysis of formation properties. With the system illustrated inFIG. 14, measurements are available in real time, and information can be combined to provide interpretations such as:

1. Resistivity as a function of depth into a formation (through frequency sweeping, measurements at multiple axial and/or azimuthal spacings, or pulsing);

2. Thickness of formation beds (through joint deconvolution of different types of logs);

Further, since the sensor modules400and the controllable element modules500may include local azimuthal and/or positional reporting mechanisms (i.e., azimuthal sensors425and530and gyroscopes430and535), it is possible to build directionally biased detection into the formation evaluation and mechanical sensors described above (either via individually interrogated sensor modules in a circular or spiral array and/or via a single sensor module being rotated with the drill pipe), and including an absolute or relative directional sensor (such as the azimuthal sensors425and530or the gyroscopes430and535) set with or indexed to the formation evaluation and mechanical sensors. Thereby, all formation evaluation and mechanical data is accompanied by real-time azimuthal information. At a sensing frequency of, for example, 120 hertz, and with the rotary turning at 120 RPM, this would provide an azimuthal resolution of 6 degrees. Using a gyroscope, the sensor placement in the well bore will be highly resolvable notwithstanding drill string precession (whirl) and bit bounce behaviors, which should be well below 100 Hz.

Further, with arrays of certain types of sensors (e.g. electromagnetic or acoustic), it is possible to synthetically steer the direction of greatest sensitivity of the array, making it possible to decouple the rate of acquisition of azimuthal measurements from the rate of rotation of the sensor package. Such measurements require rapid and near simultaneous sampling from all sensors that form the array.

Real time and moment-by-moment azimuthal and/or position indexing available with each sensor module and each controllable element module at various locations in the drill string and bottom hole assembly make possible enhanced formation and drilling process interpretations and model corrections, as well as real-time control actions. Such real-time control actions here and in a general sense as a result of this or other embodiments of the invention may be carried out directly via control signals sent from the processor to a sensor or other controllable element. But in other embodiments the data available at the surface processor, or an associated interpretation, visualization, approximation, or threshold/set-point alert or alarm, may be provided to a human user at the terminal (either on location or not), with the user then making such a real-time control decision and instructing, either through a control signal, or through manual actions (his own or those of others), to change a particular sensor or controlled element.

The various arrangements of sensor modules and controllable element modules described above can be used in making measurements while tripping. The high speed communications media190allows the measurement while tripping to proceed with no practical limitation on the rate of tripping other than sensor physics. The same arrangements can be used during the well completion process (e.g., cementing) by using “throw-away” sensors and controllable elements connected to surface real-time processing with a high-speed communications media.

The present invention is therefore well-adapted to carry out the objects and attain the ends mentioned, as well as those that are inherent therein. While the invention has been depicted, described and is defined by references to examples of the invention, such a reference does not imply a limitation on the invention, and no such limitation is to be inferred. The invention is capable of considerable modification, alteration and equivalents in form and function, as will occur to those ordinarily skilled in the art having the benefit of this disclosure. The depicted and described examples are not exhaustive of the invention. Consequently, the invention is intended to be limited only by the spirit and scope of the appended claims, giving full cognizance to equivalents in all respects.