WO2006089014A1 - Time and depth correction of mwd and wireline measurements using correlation of surface and downhole measurements - Google Patents
Time and depth correction of mwd and wireline measurements using correlation of surface and downhole measurements Download PDFInfo
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- WO2006089014A1 WO2006089014A1 PCT/US2006/005457 US2006005457W WO2006089014A1 WO 2006089014 A1 WO2006089014 A1 WO 2006089014A1 US 2006005457 W US2006005457 W US 2006005457W WO 2006089014 A1 WO2006089014 A1 WO 2006089014A1
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- Prior art keywords
- measurements
- clock
- drilling
- downhole
- time
- Prior art date
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- 238000005259 measurement Methods 0.000 title claims abstract description 108
- 238000012937 correction Methods 0.000 title description 11
- 238000005553 drilling Methods 0.000 claims abstract description 53
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 44
- 238000000034 method Methods 0.000 claims abstract description 38
- 238000011156 evaluation Methods 0.000 claims abstract description 10
- 230000015654 memory Effects 0.000 claims description 14
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- 238000012545 processing Methods 0.000 claims description 5
- 230000003287 optical effect Effects 0.000 claims description 3
- 230000002730 additional effect Effects 0.000 claims 1
- 238000005755 formation reaction Methods 0.000 description 29
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- 230000005251 gamma ray Effects 0.000 description 7
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Classifications
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/09—Locating or determining the position of objects in boreholes or wells, e.g. the position of an extending arm; Identifying the free or blocked portions of pipes
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
- G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
- G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
- G01V1/44—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators and receivers in the same well
- G01V1/46—Data acquisition
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
- G01V3/38—Processing data, e.g. for analysis, for interpretation, for correction
-
- G—PHYSICS
- G04—HOROLOGY
- G04C—ELECTROMECHANICAL CLOCKS OR WATCHES
- G04C11/00—Synchronisation of independently-driven clocks
Definitions
- This invention is related to methods for determining a depth at which measurements are made by a downhole assembly based on surface estimates of the depth and surface and downhole measurements.
- a drillbit located at the end of a drillstring is rotated so as to cause the bit to drill into the formation.
- the rate of penetration depends upon the weight on bit (WOB), the rotary speed of the drill and the formation and also the condition of the drillbit.
- WOB weight on bit
- the earliest prior art methods for measuring ROP were based on monitoring the rate at which the drillstring is lowered into the well at the surface.
- the drill string which is formed of steel pipes, is relatively long, the elasticity or compliance of the string can result in the actual ROP being different from the rate at which the string is lowered into the hole. Consequently, the depth of the bottomhole assembly (BHA) that includes the drillbit is different from that which is estimated from surface measurements alone.
- BHA bottomhole assembly
- the BHA typically includes several formation evaluation (FE) sensors that make measurements of formation properties. These include, for example, density, porosity, resistivity, and seismic velocities. Similar measurements may also be made after the well has been drilled by conveying logging instruments on a wireline or coiled tubing. Determination of properties of the formation is based upon evaluation of a suite of logs that are properly aligned in depth.
- FE formation evaluation
- response models are computed theoretically or are determined from sensor responses measured in test facilities with known environmental conditions. These sensor response models are initially stored within the downhole memory. As an alternate embodiment, sensor response models are calculated while drilling using the downhole computer and sensor responses in portions of the borehole where conditions are known. These models are then stored in the downhole memory and subsequently used for correlation in the portions of the borehole in which conditions are unknown. The depth and resolution correlated sensor responses are then processed, using combination sensor response models stored within the first storage means along with downhole computing means to obtain logs of formation parameters of interest as a function of depth within the borehole which is preferably a depth reference point.
- One embodiment of the present invention is a method of determining a difference between a first clock at a surface location and a second clock at a downhole location of a downhole assembly.
- First measurements of a first parameter of the downhole assembly are made at the surface location and a first time stamp is associated with the first measurements.
- Second measurements, similar to the first measurements, are made of the downhole assembly at the downhole location and a second time stamp is associated with the second measurements.
- the time difference is determined by matching a feature of the first measurements with a corresponding feature of the second measurements.
- the first and second measurements may be a rotational speed of a drillstring, a torque measurement and/or a pressure measurement.
- the determined time differences are used to correct formation evaluation and other downhole sensor measurements to a corrected time.
- MWD measurement while drilling
- BHA bottomhole assembly
- the system further includes a processor which determines the time difference from first measurements of a first parameter of the MWD system at the surface location and second measurements similar to the first measurements at the downhole location. The time difference is obtained by matching a feature of the first measurements with a corresponding feature of the second measurements.
- the first and second measurements may be of rotational speed or torque.
- Another embodiment of the invention is a computer readable medium for use with a measurement while drilling (MWD) system.
- the MWD system includes a first clock at a surface location a second clock on a bottomhole assembly (BHA) at a downhole location in a borehole in an earth formation.
- the second clock has a time difference relative to the first clock.
- the medium includes instructions which enable determining the time difference from first measurements of a first parameter of the MWD system at the surface location and second measurements similar to the first measurements at the downhole location. The determination is done by matching a feature of the first measurements with a corresponding feature of the second measurements.
- the medium may be selected from the group consisting of (i) a ROM 5 (ii) an EPROM, (iii) an EAROM, (iv) a Flash Memory, and, (v) an Optical disk.
- FIG. 1 (Prior Art) shows a schematic diagram of a drilling system having downhole sensor systems and accelerometers;
- FIGS. 2a and 2b are plots of surface measurements and downhole measurements of rotational speed at two different times of drilling;
- FIG. 3 a is a plot of the time difference between the surface and downhole rotational speed as a function of drilling time;
- FIG. 3b is a plot of the time difference between surface and downhole torque measurements as a function of drilling time
- FIGs. 4a and 4b show the data of Figs. 2a and 2b after correcting for the time shift;
- FIG. 5 shows the method of conversion of time-based memory data to depth-based log;
- FIG. 6 shows the correction of misalignment between FE measurements and drilling measurements using the determined time shift
- FIG. 7 shows the determination of time since drilled
- FIG. 8 shows the errors in time based logs without applying the time corrections.
- FIG. 1 shows a schematic diagram of an exemplary drilling system 10 having a downhole assembly containing an acoustic sensor system and surface devices.
- the system 10 includes a conventional derrick 11 erected on a derrick floor 12 which supports a rotary table 14 that is rotated by a prime mover (not shown) at a desired rotational speed.
- a drill string 20 that includes a drill pipe section 22 extends downward from the rotary table 14 into a borehole 26.
- a drill bit 50 attached to the drill string downhole end disintegrates the geological formations when it is rotated.
- the drill string 20 is coupled to a drawworks 30 via a kelly joint 21, swivel 28 and line 29 through a system of pulleys 27.
- the drawworks 30 is operated to control the weight on bit and the rate of penetration of the drill string 20 into the borehole 26.
- the operation of the drawworks 30 is well known in the art and is thus not described in detail herein.
- a suitable drilling fluid (commonly referred to in the art as "mud") 31 from a mud pit 32 is circulated under pressure through the drill string 20 by a mud pump 34.
- the drilling fluid 31 passes from the mud pump 34 into the drill string 20 via a desurger 36, fluid line 38 and the kelly joint 21.
- the drilling fluid is discharged at the borehole bottom 51 through an opening in the drill bit 50.
- the drilling fluid circulates uphole through the annular space 27 between the drill string 20 and the borehole 26 and is discharged into the mud pit 32 via a return line 35.
- a surface control unit 40 receives signals from the downhole sensors and devices via a sensor 43 placed in the fluid line 38 and processes such signals according to programmed instructions provided to the surface control unit.
- the surface control unit displays desired drilling parameters and other information on a display/monitor 42 which information is used by an operator to control the drilling operations.
- the surface control unit 40 contains a computer, memory for storing data, data recorder and other peripherals.
- the surface control unit 40 also includes models and processes data according to programmed instructions and responds to user commands entered through a suitable means, such as a keyboard.
- the control unit 40 is preferably adapted to activate alarms 44 when certain unsafe or undesirable operating conditions occur.
- the surface control unit also includes a surface clock (not shown).
- a drill motor or mud motor 55 coupled to the drill bit 50 via a drive shaft (not shown) disposed in a bearing assembly 57 rotates the drill bit 50 when the drilling fluid 31 is passed through the mud motor 55 under pressure.
- the bearing assembly 57 supports the radial and axial forces of the drill bit 50, the downthrust of the drill motor 55 and the reactive upward loading from the applied weight on bit.
- a stabilizer 58 coupled to the bearing assembly 57 acts as a centralizer for the lowermost portion of the mud motor assembly.
- the downhole subassembly 59 (also referred to as the bottomhole assembly or "BHA"), which contains the various sensors and MWD devices to provide information about the formation and downhole drilling parameters and the mud motor, is coupled between the drill bit 50 and the drill pipe 22.
- the downhole assembly 59 preferably is modular in construction, in that the various devices are interconnected sections so that the individual sections may be replaced when desired.
- the BHA also preferably contains sensors and devices in addition to the above-described sensors.
- Such devices may include a device for measuring the formation resistivity near and/or in front of the drillbit 50, a gamma ray device for measuring the formation gamma ray intensity and devices for determining the inclination and azimuth of the drill string 20.
- the formation resistivity measuring device 64 is may be coupled above the lower kick-off subassembly 62 that provides signals, from which resistivity of the formation near or in front of the drill bit 50 is determined.
- a dual propagation resistivity device having one or more pairs of transmitting antennae 66a and 66b spaced from one or more pairs of receiving antennae 68a and 68b may be used. Magnetic dipoles are employed which operate in the medium frequency and lower high frequency spectrum.
- the transmitted electromagnetic waves are perturbed as they propagate through the formation surrounding the resistivity device 64.
- the receiving antennae 68a and 68b detect the perturbed waves. Formation resistivity is derived from the phase and amplitude of the detected signals.
- the detected signals are processed by a downhole circuit that is preferably placed in a housing above the mud motor 55 and transmitted to the surface control unit 40 using a suitable telemetry system 72.
- the inclinometer 74 and gamma ray device 76 are suitably placed along the resistivity measuring device 64 for respectively determining the inclination of the portion of the drill string near the drill bit 50 and the formation gamma ray intensity. Any suitable inclinometer and gamma ray device, however, may be utilized for the purposes of this invention.
- an azimuth device (not shown), such as a magnetometer or a gyroscopic device, may be used to determine the drill string azimuth.
- the mud motor 55 transfers power to the drill bit 50 via one or more hollow shafts that run through the resistivity measuring device 64. The hollow shaft enables the drilling fluid to pass from the mud motor 55 to the drill bit 50.
- the mud motor 55 may be coupled below resistivity measuring device 64 or at any other suitable place.
- the drill string 20 contains a modular sensor assembly, a motor assembly and kick-off subs.
- the sensor assembly includes a resistivity device, gamma ray device and inclinometer, all of which are in a common housing between the drill bit and the mud motor.
- Such prior art sensor assemblies would be known to those versed in the art and are not discussed further.
- the downhole assembly of the present invention includes a MWD section which may contain a nuclear formation porosity measuring device, a nuclear density device and an acoustic sensor system placed above the mud motor 55 for providing information useful for evaluating and testing subsurface formations along borehole 26.
- the present invention may utilize any of the known formation density devices.
- Any prior art density device using a gamma ray source may be used.
- gamma rays emitted from the source enter the formation where they interact with the formation and attenuate.
- the attenuation of the gamma rays is measured by a suitable detector from which density of the formation is determined.
- the porosity measurement device preferably is the device generally disclosed in U.S. Pat. No. 5,144,126, which is assigned to the assignee hereof and which is incorporated herein by reference.
- This device employs a neutron emission source and a detector for measuring the resulting gamma rays. In use, high energy neutrons are emitted into the surrounding formation. A suitable detector measures the neutron energy delay due to interaction with hydrogen and atoms present in the formation.
- Other examples of nuclear logging devices are disclosed in U. S. Pat. Nos. 5,126,564 and 5,083,124.
- the above-noted devices transmit data to the downhole telemetry system 72, which in turn transmits the received data uphole to the surface control unit 40.
- the downhole telemetry also receives signals and data from the uphole control unit 40 and transmits such received signals and data to the appropriate downhole devices.
- the present invention preferably utilizes a mud pulse telemetry technique to communicate data from downhole sensors and devices during drilling operations.
- a transducer 43 placed in the mud supply line 38 detects the mud pulses responsive to the data transmitted by the downhole telemetry 72.
- Transducer 43 generates electrical signals in response to the mud pressure variations and transmits such signals via a conductor 45 to the surface control unit 40.
- Other telemetry techniques such electromagnetic and acoustic techniques or any other suitable technique may be utilized for the purposes of this invention.
- the BHA also includes a downhole processor and a downhole clock (not shown) at convenient locations.
- MWD data are collected and stored in the downhole memory during the run.
- the following procedure has been commonly used in the past: 1. Synchronize all surface computers; 2. Before the run synchronize the tool clock to the surface computer;
- This saved mismatch is used during processing of memory data as a default value for time correction.
- Fig. 2a shows the surface measured rotational speed in RPM 151 and the downhole measured rotational speed 153. As expected, the surface speed is quite uniform, but the downhole speed is somewhat irregular. The main cause for the irregularity is possible sticking and slipping of the drillstring inside the borehole.
- Torsional waves travel quite fast in the drill string and we should see changes in the downhole RPM within few seconds after RPM is changed on the surface. Such a difference is noted, and is indicated by the time 155 with a value of approximately 80 seconds. An accurate estimate of this time difference may be readily obtained by performing a cross-correlation of the smoothed downhole curve with the surface curve 151. It should be noted that the use of surface and downhole measurements of RPM is for exemplary purposes only, and the method of the present invention is applicable for any two types of measurements that are similar to each other. In this regard, the term "similar' is intended to mean having matching features.
- Fig. 2b shows similar plots of surface rotational speed 151' and downhole rotational speed 153' later in the drilling of the same well.
- the estimated time shift 155' is now only around 40 seconds. Note the difference in time scales between Fig. 21 and Fig. 2b. It is thus clear that the correction procedure outlined above would not work with a constant time shift.
- Fig. 3a the results of using a time varying time shift based on a cross-correlation of the surface and downhole measurements of rotational speed from Figs. 2a, 2b are shown.
- the curve 201 is the determined time shift
- 203 is a linear fit to 201
- 205 is the difference between the determined time shift and the linear fit Obviously there is some noise in the downhole measurements and therefore they should be approximated first by a smooth curve before using them for time correction.
- a linear time correction linear time "stretching”
- different smoothing such as a higher order polynomial may be used.
- 3b shows similar results for torque measurements: 221 is the determined time shift between surface torque measurements and downhole torque measurements while 223 is a linear fit to 221. The results are similar to those in Fig. 3a.
- Another measurement that can be used is the pressure. For example, when a drill pipe is being added to the drillstring, the mud pump is turned off. It takes a determinable time for the resulting pressure change to propagate down the borehole and reach the BHA. Any time difference over and above the determinable time is attributable to the clock.
- the surface rotary speed is determined largely by the speed of the drive motor at the surface.
- the rotary speed downhole is more affected by stick-slip effects and will thus be more erratic. As long as there is no bit bounce at the bottom, a smoothing is appropriate.
- Fig. 4a the results of shifting the downhole speed measurements of Fig. 2 a (earlier in the drilling) based on the linear shift 203 of Fig. 3 are shown.
- the downhole speed 253 tracks the surface speed 251 quite well.
- Fig. 4b shows the results of shifting the downhole speed measurements of Fig. 2b (later in the drilling) based on the linear shift 203 of Fig. 3.
- the time shifted downhole speed 253' matches the surface speed 251 ' quite well.
- FE logs are, as noted above, recorded in time and stored in a memory in the BHA.
- FIG. 5 an exemplary FE log 301 is shown. This is a function of time, and at a selected time such as 303, the FE log has a value of 311.
- the time-depth profile from surface measurements is depicted by 305. In the example shown, there is a time period when the drillbit was backed up from the bottom of the hole as seen in the negative slope of 305. At the time 303, the surface measurements would indicate a depth of the drillbit denoted by 307.
- FE log 351 (density, for this example) is shown as a function of depth using the method of Fig. 5 and without applying the time shift estimated from Fig. 3. Also shown in Fig. 6 are the weight on bit (WOB) 355, the rotary speed (RPM) 357, and the ROP 359. The WOB, RPM and ROP all shown a layer at the depth interval denoted by 363 which corresponds to a significant change in drilling conditions.
- the drilling parameter logs have a scale chosen to make the comparison with the density logs clearer.
- the density change corresponding to this drilling change is shifted by about 6 ft. in the curve 351 relative to the change in drilling conditions.
- the density change was due to a shale stringer within a sand layer.
- TSD time since drilled
- Fig. 8 Shown in Fig. 8 is the FE log displayed in time 451 without and with 453 the time shift.
- the curve 455 is the WOB
- 457 is the drilling activity code
- 459 is the RPM
- 459 is the ROP. Looking at the figure, it would not be clear whether the "spike” 471 is a spike in the measurement due to noise (which it is not), or whether it is a lithology change (which it is).
- the ROP is highly correlated with the WOB.
- US 6769407 to Dubinsky et al. having the same assignee as the present invention and the contents of which are incorporated herein by reference, teaches a method of determining ROP from downhole accelerometer measurements. Accordingly, the method of the present invention is not limited to correlating downhole RPM measurements with surface RPM measurements, and other downhole measurements, such as ROP determined from accelerometer measurements may also be used.
- the FE sensor measurements in depth can be properly aligned with sensor measurements made with wireline logging tools or with measurements made using sensors conveyed on a slickline.
- FE sensors may be at different parts of the BHA and have different time clocks with different drifts.
- the method described above provides a framework which makes it possible to compare the FE sensor data not only with drilling data but also with each other.
- the processing of the data to apply the various corrections may be accomplished in whole or in part by a downhole processor and in whole or in part by a surface processor or a combination of a. Implicit in the control and processing of the data is the use of a computer program implemented on a suitable machine readable medium that enables the processor to perform the control and processing.
- the machine readable medium may include ROMs, EPROMs, EAROMs 5 Flash Memories and Optical disks.
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- General Life Sciences & Earth Sciences (AREA)
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- Geophysics And Detection Of Objects (AREA)
- Investigating Or Analyzing Materials By The Use Of Ultrasonic Waves (AREA)
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Abstract
Description
Claims
Priority Applications (3)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
CA002597601A CA2597601A1 (en) | 2005-02-16 | 2006-02-15 | Time and depth correction of mwd and wireline measurements using correlation of surface and downhole measurements |
GB0715746A GB2437885A (en) | 2005-02-16 | 2006-02-15 | Time and depth correction of MWD and wireline measurements using correlation of surface and downhole measurements |
NO20074146A NO20074146L (en) | 2005-02-16 | 2007-08-10 | Time and depth correction for signal transmission via drill string and wire line paints using correlation of surface and well paints |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US11/058,774 US20060180349A1 (en) | 2005-02-16 | 2005-02-16 | Time and depth correction of MWD and wireline measurements using correlation of surface and downhole measurements |
US11/058,774 | 2005-02-16 |
Publications (1)
Publication Number | Publication Date |
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WO2006089014A1 true WO2006089014A1 (en) | 2006-08-24 |
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PCT/US2006/005457 WO2006089014A1 (en) | 2005-02-16 | 2006-02-15 | Time and depth correction of mwd and wireline measurements using correlation of surface and downhole measurements |
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Country | Link |
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US (1) | US20060180349A1 (en) |
CA (1) | CA2597601A1 (en) |
GB (1) | GB2437885A (en) |
NO (1) | NO20074146L (en) |
WO (1) | WO2006089014A1 (en) |
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US7969819B2 (en) * | 2006-05-09 | 2011-06-28 | Schlumberger Technology Corporation | Method for taking time-synchronized seismic measurements |
US8902695B2 (en) * | 2006-12-06 | 2014-12-02 | Baker Hughes Incorporated | Apparatus and method for clock shift correction for measurement-while-drilling measurements |
US20110085415A1 (en) * | 2009-10-09 | 2011-04-14 | Morton Peter J | Method for synchronizing seismic data recorded by two or more separate recording systems |
US9103940B2 (en) * | 2009-12-03 | 2015-08-11 | Shell Oil Company | Seismic clock timing correction using ocean acoustic waves |
US20110203805A1 (en) * | 2010-02-23 | 2011-08-25 | Baker Hughes Incorporated | Valving Device and Method of Valving |
US9297733B2 (en) | 2010-03-09 | 2016-03-29 | Cidra Corporate Services Inc. | Dispersion compensation technique for differential sonar measurement—density meter |
US9146334B2 (en) * | 2011-09-13 | 2015-09-29 | Baker Hughes Incorporated | Method of phase synchronization of MWD or wireline apparatus separated in the string |
US20150218929A1 (en) * | 2014-02-04 | 2015-08-06 | Schlumberger Technology Corporation | Well-Logging System With Data Synchronization And Methods |
US9828845B2 (en) * | 2014-06-02 | 2017-11-28 | Baker Hughes, A Ge Company, Llc | Automated drilling optimization |
US10280739B2 (en) | 2014-12-05 | 2019-05-07 | Halliburton Energy Services, Inc. | Downhole clock calibration apparatus, systems, and methods |
EP3294987B1 (en) * | 2015-05-13 | 2023-02-22 | ConocoPhillips Company | Time corrections for drilling data |
WO2016183168A1 (en) * | 2015-05-13 | 2016-11-17 | Conocophillips Company | Time corrections for drilling data |
CA2988953C (en) * | 2015-06-26 | 2023-05-23 | Shell Internationale Research Maatschappij B.V. | Method of calibrating depths of a seismic receiver array |
US9971054B2 (en) | 2016-05-31 | 2018-05-15 | Baker Hughes, A Ge Company, Llc | System and method to determine communication line propagation delay |
AU2017355984B2 (en) | 2016-10-06 | 2020-04-09 | Shell Internationale Research Maatschappij B.V. | Method of borehole time-lapse monitoring using seismic waves |
US11125074B2 (en) | 2018-04-26 | 2021-09-21 | Nabors Drilling Technologies Usa, Inc. | Marker signal for subterranean drilling |
NO20220936A1 (en) | 2020-02-20 | 2022-08-31 | Baker Hughes Oilfield Operations Llc | Incremental downhole depth methods and systems |
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2005
- 2005-02-16 US US11/058,774 patent/US20060180349A1/en not_active Abandoned
-
2006
- 2006-02-15 CA CA002597601A patent/CA2597601A1/en not_active Abandoned
- 2006-02-15 WO PCT/US2006/005457 patent/WO2006089014A1/en active Application Filing
- 2006-02-15 GB GB0715746A patent/GB2437885A/en not_active Withdrawn
-
2007
- 2007-08-10 NO NO20074146A patent/NO20074146L/en not_active Application Discontinuation
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Also Published As
Publication number | Publication date |
---|---|
CA2597601A1 (en) | 2006-08-24 |
GB0715746D0 (en) | 2007-09-19 |
NO20074146L (en) | 2007-11-13 |
US20060180349A1 (en) | 2006-08-17 |
GB2437885A (en) | 2007-11-07 |
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