Patent Application
20060185900
None.
The present invention relates generally to a method of communicating information from the surface to a downhole device located in a subterranean borehole. More particularly, exemplary embodiments of this invention relate to a method of encoding tool commands in a combination of drill string rotation rate and drilling fluid flow rate variations. Exemplary embodiments of the invention also relate to a differential programming method in which relative changes to current tool parameters are encoded.
Oil and gas well drilling operations commonly use sensors deployed downhole as a part of the drill string to acquire data as the well bore is being drilled. This real-time data may provide information about the progress of the drilling operation or the earth formations surrounding the well bore. Significant benefit may be obtained by improved control of downhole sensors from the rig floor or from remote locations. For example, the ability to send commands to downhole sensors that selectively activate the sensors can conserve the battery life of the sensors and increase the amount of downhole time a sensor is useful.
Directional drilling operations are particularly enhanced by improved control. The ability to efficiently and reliably transmit commands from an operator to downhole drilling hardware may enhance the precision of the drilling operation. Downhole drilling hardware that, for example, deflects a portion of the drill string to steer the drilling tool is typically more effective when under tight control by an operator. The ability to continuously adjust the projected direction of the well path by sending commands to a steering tool may enable an operator to fine tune the projected well path based on substantially real-time survey data. In such applications, both accuracy and timeliness of data transmission are clearly advantageous.
Prior art communication techniques that rely on the rotation rate of the drill string to encode data are known. For example, Webster, in U.S. Pat. No. 5,603,386, discloses a method in which the absolute rotation rate of the drill string is utilized to encode data. While the Webster technique is serviceable, improvements could be made. For example, the optimum rotation rate of the drill string may vary within an operation, or from one operation to the next, depending on the type of drill bit being used and the strata being penetrated. As such, frequent reprogramming of the absolute rotation rates is sometimes required.
U.S. Patent Application 20050001737, to Baron et al., which is commonly assigned with the present application, discloses another technique for encoding data that also relies on the rotation rate of the drill string. The Baron technique advantageously overcomes the above-described difficulty, for example, by utilizing a difference between first and second rotation rates to encode data. While this approach is serviceable it may be improved upon for certain downhole applications. For example, drilling applications may be encountered in which the drill string sticks and/or slips in the borehole. This is a condition commonly referred to in the art as stick/slip, and is known to cause a non-uniform drill string rotation rate. In stick/slip situations, precise measurement of the drill string rotation rate sometimes becomes problematic. Therefore, there exists a need for improved techniques for communicating from the surface to a downhole tool.
The present invention addresses one or more of the above-described drawbacks of prior art downhole communication methods. Aspects of this invention include a method for communicating with a downhole tool, such as a downhole steering tool, that is connected to a drill string and deployed in a subterranean borehole. Exemplary embodiments of the method include encoding data and/or commands in a sequence of varying drill string rotation rates and drilling fluid flow rates. The varying rotation rates and flow rates are measured downhole and processed to decode the data and/or the commands. In one exemplary embodiment, commands in the form of relative changes to steering tool offset and tool face settings are encoded and transmitted downhole. Such commands may then be executed, for example, to change the steering tool settings and thus the direction of drilling the borehole.
Exemplary embodiments of the present invention may advantageously provide several technical advantages. For example, exemplary methods according to this invention provide for quick and accurate communication with a downhole tool, such as a sensor or a downhole drilling tool. In particular, the use of both rotation rate and flow rate encoding tends to provide for increased bandwidth as compared to prior art encoding methods. Moreover, the use of a differential encoding scheme, in which a relative change in the value of a tool parameter is encoded, may also be advantageous. Such a differential approach tends to reduce the quantity of encoded information and thereby may further reduce transmission time as compared to the prior art.
The use of a differential encoding scheme may also be advantageous in that it tends to require fewer distinct commands than direct programming methods of the prior art. As such, fewer rotation rate and/or flow rate levels are required to encode those commands, which tends to increase accuracy by decreasing the likelihood of transmitting erroneous commands. Moreover, having fewer rotation rate levels may be advantageous in certain applications in which accurate measurement of the rotation rate is problematic (e.g., in stick/slip situations, as described above).
Exemplary embodiments of this invention may be further advantageous in that surface to downhole communication may be accomplished without substantially interrupting the drilling process. Rather, data and/or commands may be encoded in drill string rotation rate and drilling fluid flow rate variations and transmitted downhole during drilling. Additionally, the present invention may advantageously be utilized at substantially any conventional rotation rate being employed to drill a borehole. As such, the invention tends to be suitable for use with substantially any drilling rig configuration without the need for reprogramming and/or reconfiguration of the command parameters.
In one aspect the present invention includes a method for communicating with a downhole tool deployed in a subterranean borehole. The method includes deploying a drill string in a subterranean borehole, the drill string including a downhole tool connected thereto, the drill string being rotatable about a longitudinal axis, the drill string including a rotation measurement device operative to measure rotation rates of the drill string about the longitudinal axis, the drill string further including a flow measurement device operative to measure flow rates of drilling fluid in the drill string. The method further includes predefining an encoding language comprising codes understandable to the downhole device, the codes represented in said language as predefined value combinations of drill string rotation variables and drilling fluid flow variables, the drill string rotation variables including rotation rate, the drilling fluid flow variables including flow rate. The method still further includes causing the drill string to rotate at a preselected rotation rate, causing the drilling fluid to flow in the drill string at a preselected flow rate, and causing the rotation measurement device to measure the rotation rate and the flow measurement device to measure the flow rate. The method yet further includes processing downhole the measured rotation rate and flow rate to acquire at least one code in said language at the downhole tool.
In another exemplary aspect the present invention includes a method for communicating with a downhole tool deployed in a subterranean borehole. The method includes deploying a drill string in a subterranean borehole, the drill string including a downhole tool connected thereto, the drill string being rotatable about a longitudinal axis, the drill string including a rotation measurement device operative to measure rotation rates of the drill string about the longitudinal axis. The method further includes predefining an encoding language comprising codes understandable to the steering tool, the codes represented in said language as predefined value combinations of drill string variables including drill string rotation variables, said drill string rotation variables including rotation rate. The method still further includes causing the drill string to rotate at a preselected rotation rate and causing the rotation measurement device to measure the rotation rate. The method also includes processing downhole the measured rotation rate to acquire at least one code in said language at the downhole tool, the downhole tool recognizing at least one of said acquired codes as a command to make a predetermined relative change to at least one of its current tool settings.
In still another aspect the present invention includes a method for communicating with a downhole tool deployed in a subterranean borehole. The method includes deploying a drill string in a subterranean borehole, the drill string including a downhole tool connected thereto, the drill string being rotatable about a longitudinal axis, the drill string including a rotation measurement device operative to measure rotation rates of the drill string about the longitudinal axis, the drill string further including a flow sensing device operative to measure flow of drilling fluid in the drill string. The method further includes predefining an encoding language comprising codes understandable to the downhole device, the codes represented in said language as predefined value combinations of drill string rotation variables and drilling fluid flow variables, the drill string rotation variables including rotation rate. The method still further includes causing the drill string to rotate at a preselected rotation rate, causing the drilling fluid to flow in the drill string at a preselected flow rate, causing the rotation measurement device to measure the rotation rate of the drill string, and causing the flow sensing device to measure the flow of the drilling fluid, the flow measured as a binary variable including high and low flow levels. The method also includes processing downhole the measured rotation rate and the measured flow to acquire at least one code in said language at the downhole tool, the at least one code acquired at the tool only when the measured flow is detected to be at a preselected one of the high and low flow levels.
The foregoing has outlined rather broadly the features of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter which form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other methods, structures, and encoding schemes for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.
For a more complete understanding of the present invention, and the advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:
In the exemplary embodiment shown, directional drilling tool 100 includes one or more (e.g., three) blades 110 disposed to extend from directional drilling tool 100 and apply a lateral force and/or displacement to the borehole wall 42 in order to deflect the drill string 30 from the central axis of the borehole 40 and thus change the drilling direction. Directional drilling tool 100 further includes one or more sensors 120 for measuring, for example, the rotation rate of the drill string 30 and the flow rate of drilling fluid in the drill string 30. Sensors 120 may alternatively be deployed elsewhere in the drill string 30. Drill string 30 may further include a measurement while drilling (MWD) tool 150 including one or more surveying sensors, such as accelerometers, magnetometers, and/or gyroscopes. Drill string 30 may further include substantially any other downhole tools coupled thereto, such as logging while drilling (LWD) tools, formation sampling tools, a telemetry system for communicating with the surface, and the like.
It will be understood by those of ordinary skill in the art that methods in accordance with this invention are not limited to use with a semisubmersible platform 12 as illustrated in
With continued reference to
Embodiments of this invention may utilize substantially any transmission system 60 for controlling the rotation rate of drill string 30 and the flow rate of drilling fluid in the drill string 30. For example, transmission system 60 may employ manual control of the rotation rate and/or flow rate, for example via known rheostatic control techniques. On drilling rigs including such manual control mechanisms, rotation rate and flow rate encoded data in accordance with this invention may be transmitted by manually adjusting the rotation and/or flow rates, e.g., in consultation with a timer. Alternatively, transmission system 60 may employ computerized control of the rotation rate and/or flow rate. In such systems, an operator may input a desired rotation rate and/or flow rate via a suitable user interface such as a keyboard or a touch screen. In one advantageous embodiment, transmission system 60 may include a computerized system in which an operator inputs the data and/or the command to be transmitted. For example, for a downhole steering tool, an operator may input desired tool face and offset values (as described in more detail below). The transmission system 60 then determines a suitable sequence of rotation rate and flow rate changes and executes the sequence to transmit the data and/or commands to the tool 100.
With further reference now to
As described above with respect to
It has been found in certain applications (particularly when the drill bit 32 is off bottom) that a “non-rotating” housing sometimes rotates relative to the borehole. The rotation of the housing is typically at a lower rate than that of the drive shaft, but may, in some instances, be significant. In such instances, it may be advantageous to measure the rotation of both the drive shaft relative to the housing (as described above in the preceding paragraph) and the housing relative to the borehole. The sum of (or the difference between) the two rotation rates may then be taken as the rotation rate of the drill string. Substantially any known technique may be utilized for measuring the rotation rate of the housing. For example, a device that senses changes in centrifugal force may be used to determine the rotation rate of the housing. Alternatively, a terrestrial reference, such as gravity or the Earth's magnetic field, may be measured, for example, using tri-axial accelerometers, tri-axial magnetometers, and/or gyroscopes.
It will be appreciated that this invention may also be employed in downhole tools that are rotationally coupled with the drill string 30. In such embodiments, substantially any known technique may be utilized to measure rotation rate, such as a measurement of a terrestrial reference as described above.
Sensors 120 (
With continued reference to
A suitable controller 130 typically includes a timer and electronic memory such as volatile or non-volatile memory. The timer may include for example, an incrementing counter, a decrementing time-out counter, or a real-time clock. Controller 130 may further include a data storage device, various sensors, other controllable components, a power supply, and the like. Controller 130 may also include conventional receiving electronics, for example for receiving and amplifying pulses from sensor 122. Controller 130 may also optionally communicate with other instruments in the drill string, such as telemetry systems that communicate with the surface. It will be appreciated that controller 130 is not necessarily located in directional drilling tool 100, but may be disposed elsewhere in the drill string in electronic communication with directional drilling tool 100. Moreover, one skilled in the art will readily recognize that the multiple functions performed by the controller 130 may be distributed among a number of devices.
Reference should now be made to
Various alternative exemplary embodiments of encoding schemes, in accordance with the present invention, are described, in conjunction with
One aspect of each of the exemplary encoding schemes described in conjunction with
Turning now to
In the exemplary embodiment shown on
It will be appreciated that numerous code sequence validation checks may be utilized to determine the validity of waveforms 240 and 260. For example, each pulse may require an increase of at least a certain degree within a predetermined time limit to be considered a valid pulse (e.g., an increase of at least 20 rpm at 244 within 30 seconds for waveform 240). The rotation rate 246 and flow rate 266 may also be required to remain essentially constant (e.g., within about 20 rpm for waveform 240) for the entire duration of the pulse. Moreover, validity (or invalidity) may also be determined via duration measurements. For example, in certain embodiments, a valid sequence only occurs when C1 is approximately equal to C3 (e.g., within about 20 seconds). Additionally, pulses having durations that are either too short or too long may be discarded (e.g., less than 60 seconds and greater than 180 seconds). In still other exemplary embodiments, pulses 246 and 266 may be predefined to start and/or end at substantially the same time (e.g., within about 10 seconds of one another). The invention is not limited to the above described exemplary validation checks.
It will also be appreciated that numerous factors may be considered in determining the duration of a pulse (or some other feature of a code sequence). Such factors include, for example, the resolution of the rotation and/or flow rate measurements, the range of valid rotation and/or flow rates, the amount of time required to obtain accurate rotation and/or flow rate measurements, the accuracy of the encoding mechanism, the changes in duration in a particular sequence due to propagation of the rotation and/or fluid flow through the drill string, and the required accuracy of the decoding mechanism. A particular scheme may delineate the interval for measuring the duration of a pulse in any one of a variety of ways. For example, the duration of a pulse may be defined as the time interval between an increase of a predefined amount above the base level 242, 262 and a return to that base level 250, 270 (within predefined limits). Alternatively, the duration may be begin when the when the elevated level 246, 266 is achieved and end when the rotation rate or flow rate decreases below that level. Again, the invention is not limited in these regards.
Turning now to
In the exemplary embodiment shown on
It will be appreciated that in certain applications and/or utilizing certain downhole tool combinations, direct measurement of drilling fluid flow rates may not be possible. Nevertheless, in such embodiments, a combination of rotation rate and flow rate encoding is possible. Turning now to
In the exemplary embodiment shown on
Exemplary encoding schemes of this invention (such as that shown on
One exemplary encoding scheme of the present invention is now described in more detail with respect to TABLES 1 through 4 and
Offset and tool face, as used herein, refer to the magnitude (typically in inches) and direction (typically in degrees relative to high side) of the eccentricity of the steering tool axis from the borehole axis. Such eccentricity tends to alter an angle of approach of a drill bit and thereby change the drilling direction. The magnitude and direction of the offset are typically controllable, for example by controlling the relative radial positions of the steering tool blades. In general, increasing the offset (i.e., increasing the distance between the tool axis and the borehole axis) tends to increase the curvature (dogleg severity) of the borehole upon subsequent drilling. Moreover, in a “push the bit” configuration, the direction (tool face) of subsequent drilling tends to be the same (or nearly the same depending, for example, upon local formation characteristics) as the direction of the offset between the tool axis and the borehole axis. For example, in a push the bit configuration a steering tool offset at a tool face of about 90 degrees (relative to high side) tends steer the drill bit to the right upon subsequent drilling. The artisan of ordinary skill will readily recognize that in a “point the bit” configuration, the direction of subsequent drilling tends to be in the opposite direction as the tool face (i.e., to the left in the above example). It will be appreciated that the invention is not limited to the above described steering tool embodiments.
Referring again to TABLES 1 through 4, relative changes to the current tool face and offset settings are encoded based upon unique combinations of codes C1 and C2 shown on
Referring now to TABLE 1, an UP command is executed when the rotation rate of the pulse is at least 20 rpm greater than the base rotation rate (i.e., C2≧20). A DOWN command is executed when the rotation rate of the pulse is at least 20 rpm less than the base rotation rate (i.e., C2<−20). The UP and DOWN commands refer to relative changes to the current tool face setting. UP refers to a rotation of the tool face about the horizontal axis (i.e., the 90-270 degree axis) to the upper quadrants. DOWN refers to a rotation of the tool face about the horizontal axis (i.e., the 90-270 degree axis) to the lower quadrants. For example, if the current tool face is 30 degrees (relative to high side), an UP command leaves the tool face unchanged since it is already in one of the upper quadrants. A DOWN command rotates the tool face symmetrically about the horizontal axis from 30 degrees to 150 degrees. In another example, if the current tool face is 225 degrees, an UP command rotates the tool face symmetrically about the horizontal axis from 225 degrees to 315 degrees (i.e., −45 degrees). A DOWN command leaves the tool face unchanged since it is already in the one of the lower quadrants.
Turning now to TABLE 2, a RIGHT command is executed when the rotation rate of the pulse is at least 20 rpm greater than the base rotation rate (i.e., C2≧20). A LEFT command is executed when the rotation rate of the pulse is at least 20 rpm less than the base rotation rate (i.e., C2<−20). The RIGHT and LEFT commands refer to relative changes to the current tool face setting. RIGHT refers to a rotation of the tool face about the vertical axis (i.e., the 0-180 degree axis) to the right quadrants. LEFT refers to a rotation of the tool face about the vertical axis (i.e., the 0-180 degree axis) to the left quadrants. For example, if the current tool face is 30 degrees (relative to high side), a RIGHT command leaves the tool face unchanged since it is already in one of the right quadrants. A LEFT command rotates the tool face symmetrically about the vertical axis from 30 degrees to 330 degrees (i.e., −30 degrees). In another example, if the current tool face is 225 degrees, a RIGHT command rotates the tool face symmetrically about the vertical axis from 225 degrees to 135 degrees. A LEFT command leaves the tool face unchanged since it is already in the one of the left quadrants.
With reference now to TABLE 3, when the rotation rate of the pulse is within 20 rpm of the base rotation rate, a fast blade collapse command is executed. This command fully retracts each of the steering tool blades, for example, in preparation of removing the tool from the borehole. When the rotation rate of the pulse is at least 20 rpm greater than the base rotation rate (i.e., C2≧20), the current tool face setting is increased by 30 degrees. Upon receipt of such a command, a tool face of 45 degrees, for example, is increased to 75 degrees. When the rotation rate of the pulse is at least 20 rpm less than the base rotation rate (i.e., C2<−20), the current tool face setting is decreased by 30 degrees. Upon receipt of such a command, a tool face of 45 degrees, for example, is decreased to 15 degrees.
Referring now to TABLE 4, when the rotation rate of the pulse is within 20 rpm of the base rotation rate, a HOLD or CRUISE command is executed. A HOLD command instructs the steering tool to maintain the current inclination of the borehole and in this exemplary embodiment is only executed when the current tool face is 0 degrees. A CRUISE command instructs the steering tool to maintain both the current inclination and the current azimuth. The CRUISE command is executed when the current tool face is not equal to 0 degrees. When the rotation rate of the pulse is at least 20 rpm greater than the base rotation rate (i.e., C2≧20), the current offset setting is increased by 0.1 inches. Upon receipt of such a command, an offset of 0.2 inches, for example, is increased to 0.3 inches. When the rotation rate of the pulse is at least 20 rpm less than the base rotation rate (i.e., C2<−20), the current offset is decreased by 0.1 inches. Upon receipt of such a command, an offset of 0.2 inches is decreased to 0.1 inches.
As stated above, multiple commands may be transmitted downhole via encoding two or more pulses. For example, in order to change both the tool face and offset, a first pulse may be utilized to change the tool face and a second pulse may be utilized to change the offset. In other instances, multiple pulses may be utilized to change the tool face or offset settings. For example, in the exemplary embodiment shown in TABLES 1 through 4, first and second consecutive pulses may be utilized to increase the offset by a total of 0.2 inches by causing each pulse to increase the offset by 0.1 inch. In another example, the tool face may be changed from 45 degrees to 225 degrees by first transmitting a DOWN command and then transmitting a LEFT command. It will be understood that the invention is not limited by such examples, which are disclosed here for purely illustrative purposes. The artisan of ordinary skill will readily recognize that numerous command combinations may be utilized to program a particular change in tool face and offset settings. Moreover, the invention is not limited to the exemplary commands shown on TABLES 1 through 4.
It will be appreciated that the use of a differential encoding method, such as that described above with respect to TABLES 1 through 4, in which a relative change in current tool face and/or offset settings is encoded may be advantageous for some applications. Such a differential approach may reduce the amount of information required to be encoded, and therefore may reduce the time required to transmit a command downhole, as compared to prior art methods that directly encode the tool face and offset settings. Often it is desirable to make small changes to the drilling direction, for example, due to drift from a desired course. Exemplary embodiments of this invention are well suited for making such small changes, for example, by increasing or decreasing the tool face or the offset settings. Such small changes may often be advantageously encoded in a single pulse, which saves valuable rig time. Prior art approaches that directly encode the tool face and offset settings may require as many as three pulses to encode new tool face and offset. Moreover, since exemplary embodiments of this invention require fewer distinct commands than certain methods of the prior art, fewer rotation rate levels are required to encode those commands. As such, exemplary embodiments of this invention may advantageously be utilized in applications in which accurate measurement of the rotation rate is sometimes problematic (e.g., due to stick slip problems).
Referring now to
Method embodiment 500 utilizes a base rotation rate, which is established for this particular embodiment when the rotation rate of the drill string (e.g., drill string 30 shown on
With continued reference to the flow diagram of
With reference now to
At STATE 1 the program waits for a decrease in rotation rate below the base rate established in STATE 0. RATE is repeatedly sampled (e.g., once per second) at 512 and 514 to determine whether it changes from BASE. If RATE is determined at 512 to increase by at least 20 rpm over BASE, then the base rate is invalidated and the program returns to 502. If RATE is determined at 514 to decrease by at least 20 rpm below BASE, then the program waits 30 seconds at 516 before setting STATE equal to 2 at 518.
If a valid code sequence has been initiated, RATE decreases to less than 10 rpm and FLOW is switched from high to low during the 30 second delay. At 520 and 521 (when STATE equals 2) the program checks RATE and FLOW to determine whether these conditions are met. If either condition has not been met, the established base rate is invalidated and the program returns to 502. In this exemplary embodiment, FLOW is also periodically checked in the background. If FLOW is high at any time while STATE equals 3 through 8, the code sequence is invalidated and the program returns to 502 and sets STATE equal to 0. At 522 the program also checks that BASE is greater than 30 rpm. If BASE is greater than 30 rpm, STATE is set equal to 3 at 524. If BASE is less than 30 rpm an invalid base rotation rate has been established and the program returns to 502.
In a valid code sequence, the rotation rate remains below 10 rpm for at least 30 seconds prior to a rotation rate pulse. At STATE 3, TIMER is reset at 526 and the program checks RATE once per second at 528. If RATE is greater than 10 rpm, the program returns to 524 where STATE is again set equal to 3 and TIMER is reset. If rate is less than 10 rpm and TIMER is greater than or equal to 30 seconds at 530 (indicating that RATE has remained less than 10 rpm for at least 30 seconds), STATE is set equal to 4 at 532 (
With reference now to
At STATE 5 the program waits 40 seconds for the RATE to average up at 538 and then checks that RATE is greater than 30 rpm at 540. In the exemplary embodiment shown, the rotation rate of a valid pulse is greater than 30 rpm. If RATE is less than 30 rpm at 540, an invalid pulse has been detected and the program returns to 524 and sets STATE equal to 3. If RATE is greater than or equal to 30 rpm at 540, STATE is set equal to 6 at 542.
At STATE 6 the program saves the rotation rate of the pulse each second, checks the validity of the pulse, and awaits the end of the pulse. At 544 TIMER is reset. At 546 RPM(i) is set equal to RATE. RPM(i) are saved to memory and represent rotation rate values measured each second during the duration of the pulse. At 548 the program checks that RATE is within plus or minus 30 rpm of RPM(1) (the first measured rate of the pulse). If not the pulse is invalidated and the program returns to 524 where STATE is set equal to 3 (
Turning now to
At STATE 8 the command is applied at 570 to reprogram the tool. For example, in this exemplary embodiment, if the command is to increase the tool face by 30 degrees, then the tool is instructed to increase tool face by 30 degrees over its current setting. After application of the command at 570, the program checks FLOW at 572. If FLOW is high, the program returns to 502 and sets STATE equal to 0 (
Although the present invention and its advantages have been described in detail, it should be understood that various changes, substitutions and alternations can be made herein without departing from the spirit and scope of the invention as defined by the appended claims.
