CA2518938A1 - Determination of the orientation of a downhole device - Google Patents
Determination of the orientation of a downhole device Download PDFInfo
- Publication number
- CA2518938A1 CA2518938A1 CA002518938A CA2518938A CA2518938A1 CA 2518938 A1 CA2518938 A1 CA 2518938A1 CA 002518938 A CA002518938 A CA 002518938A CA 2518938 A CA2518938 A CA 2518938A CA 2518938 A1 CA2518938 A1 CA 2518938A1
- Authority
- CA
- Canada
- Prior art keywords
- signal
- movable member
- assembly
- orientation
- trigger means
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Abandoned
Links
Classifications
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01C—MEASURING DISTANCES, LEVELS OR BEARINGS; SURVEYING; NAVIGATION; GYROSCOPIC INSTRUMENTS; PHOTOGRAMMETRY OR VIDEOGRAMMETRY
- G01C21/00—Navigation; Navigational instruments not provided for in groups G01C1/00 - G01C19/00
- G01C21/10—Navigation; Navigational instruments not provided for in groups G01C1/00 - G01C19/00 by using measurements of speed or acceleration
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01C—MEASURING DISTANCES, LEVELS OR BEARINGS; SURVEYING; NAVIGATION; GYROSCOPIC INSTRUMENTS; PHOTOGRAMMETRY OR VIDEOGRAMMETRY
- G01C1/00—Measuring angles
Abstract
For measuring the orientation of an offset stabiliser device in a downhole environment. A shaft rotates relative to the stabiliser device, and signal trigger means are provided at known locations on each of the rotating shaft and the stabiliser device. When the signal trigger means on each component are brought into alignment, a signal is triggered and a pressure pulse is generated. The timing of the generated signals are used together with the measured orientation of the shaft, obtained using an angular measurement sensor such as an accelerometer and/or magnetometer, in order to calculate the orientation of the offset stabiliser device.
Description
1 Determination of Device Orientation
2
3 The present invention relates to the determination
4 of device orientation, in particular to a a downhole assembly and to a method of determining the 6 orientation of a downhole device.
8 There are many situations where it is important yet 9 difficult to measure the orientation of a device.
In particular, in a drilling environment, when 11 performing a drilling operation, the trajectory of a 12 drill bit can be controlled by varying the angular 13 position of an offset stabiliser device. In order 14 to control the drilling process, it is therefore essential to know the orientation of the offset 16 stabiliser device.
18 . However, this is difficult and cumbersome to i 19 monitor. Conventionally, the drillstring has to be mechanically disengaged to enable the measuring of 21 the stabiliser orientation, and then re-engaged 22 again before drilling can be resumed. This process CONFIRMATION COPY
1 uses up a lot of time, adding to the difficulty and 2 cost, and detracting from the efficiency of the 3 overall drilling operation.
This effort, time and expenditure Could be reduced 6 if there was an effective way of making a remote 7 measurement of the orientation of an offset 8 stabiliser or similar orientation determination or 9 steering device remote from the system.
11 According to a first aspect of the present 12 invention, there is provided a downhole assembly as 13 set out in the attached claim 1.
According to a second aspect of the present 16 invention, there is provided a method of determining 17 the orientation of a downhole device, as set out in 18 the attached claim 22.
The present invention will now be described with 21 reference to the accompanying drawings, in which:
23 Fig. 1 shows an assembly incorporating one 24 embodiment of the present invention;
26 Fig. 2 illustrates the functioning of 27 instrumentation used in the present invention; and 29 Fig. 3 shows a cross-sectional view of part of the assembly shown in Fig. 1.
1 Fig. 1 shows an assembly 10 where the trajectory 12 2 of a drillbit 14 is defined by the angular position 3 of an offset stabiliser device 30 which will force 4 the drillbit 14 in a particular direction. A sleeve 31 is mounted on a_ central rotating shaft 20 on 6 bearings such that when the shaft 20 rotates the 7 sleeve 31 remains relatively rotationally stable.
9 The sleeve 31 can have a slight offset 34 such that the offset 34 is positioned to force the drillstring 11 14 in a particular direction 12. It is therefore 12 critical to understand the orientation of the sleeve 13 offset 34 in order to determine the direction 12 in 14 which the bit 14 is being pushed.
16 A directional measurement system is mounted on the 17 rotating shaft 20 that includes measurement 18 instruments to determine the rotational position of 19 the shaft 20 relative to the earth's gravitational field, magnetic field or inertial rotational field.
21 Alternatively, a resolver arrangement may be used to 22 a known reference.
24 The measurement instruments used in a preferred embodiment of the present invention are a three axis 26 accelerometer and three axis magnetometer assembly 27 configured with X, Y and z axes. The Z axis is 28 defined as the axis along the tool string, the Y
29 axis is aligned along the toolface datum, and the .X
axis is oriented such that the X, Y and Z axes form 31 a set defining the directions of basis vectors to 1 define position of the tool with respect to the 2 earth's gravitational anal magnetic fields.
4 The output of the accelerometer is expressed as a gravity function Gf, having components G,~, G~, and GZ
6 in the frame of reference. Gf is defined by:
- sin(Il~IC)sin(G'~I'F7 8 gf(Cat, GTF,IlI~C) = Gt - sin(INC)c~s((~'TF) Eqn 1 cos(I1~1C) where Gt is the vector sum of the total gravity 11 field, INC is the angle of inclination of the Z axis 12 from the vertical, and GTF is a parameter called the 13 Gravity Tool Face, defined as the angle between the 14 Y axis and the projection of the earth's gravitational field vector onto the X-Y plane.
17 GTF is equivalent to the roll angle of the tool 18 where the reference point or scribe line is in line 19 with the Y-axis.
21 The output of the magnetometer is expressed as a 22 magnetic function Hf, having components HX, Hy, and 23 HZ in the frame of reference. Hf is defined by 24 equation 2, which is attached as an appendix to this description.
27 In equation 2, Ht is the vector sum of the total 28 magnetic field, A~ is the magnetic azimuth relative 29 to magnetic north, and DIP is the angle down to the 1 earth's magnetic field vector from its projection on 2 the horizontal azimuth.
4 The above outputs can be algebraically manipulated
8 There are many situations where it is important yet 9 difficult to measure the orientation of a device.
In particular, in a drilling environment, when 11 performing a drilling operation, the trajectory of a 12 drill bit can be controlled by varying the angular 13 position of an offset stabiliser device. In order 14 to control the drilling process, it is therefore essential to know the orientation of the offset 16 stabiliser device.
18 . However, this is difficult and cumbersome to i 19 monitor. Conventionally, the drillstring has to be mechanically disengaged to enable the measuring of 21 the stabiliser orientation, and then re-engaged 22 again before drilling can be resumed. This process CONFIRMATION COPY
1 uses up a lot of time, adding to the difficulty and 2 cost, and detracting from the efficiency of the 3 overall drilling operation.
This effort, time and expenditure Could be reduced 6 if there was an effective way of making a remote 7 measurement of the orientation of an offset 8 stabiliser or similar orientation determination or 9 steering device remote from the system.
11 According to a first aspect of the present 12 invention, there is provided a downhole assembly as 13 set out in the attached claim 1.
According to a second aspect of the present 16 invention, there is provided a method of determining 17 the orientation of a downhole device, as set out in 18 the attached claim 22.
The present invention will now be described with 21 reference to the accompanying drawings, in which:
23 Fig. 1 shows an assembly incorporating one 24 embodiment of the present invention;
26 Fig. 2 illustrates the functioning of 27 instrumentation used in the present invention; and 29 Fig. 3 shows a cross-sectional view of part of the assembly shown in Fig. 1.
1 Fig. 1 shows an assembly 10 where the trajectory 12 2 of a drillbit 14 is defined by the angular position 3 of an offset stabiliser device 30 which will force 4 the drillbit 14 in a particular direction. A sleeve 31 is mounted on a_ central rotating shaft 20 on 6 bearings such that when the shaft 20 rotates the 7 sleeve 31 remains relatively rotationally stable.
9 The sleeve 31 can have a slight offset 34 such that the offset 34 is positioned to force the drillstring 11 14 in a particular direction 12. It is therefore 12 critical to understand the orientation of the sleeve 13 offset 34 in order to determine the direction 12 in 14 which the bit 14 is being pushed.
16 A directional measurement system is mounted on the 17 rotating shaft 20 that includes measurement 18 instruments to determine the rotational position of 19 the shaft 20 relative to the earth's gravitational field, magnetic field or inertial rotational field.
21 Alternatively, a resolver arrangement may be used to 22 a known reference.
24 The measurement instruments used in a preferred embodiment of the present invention are a three axis 26 accelerometer and three axis magnetometer assembly 27 configured with X, Y and z axes. The Z axis is 28 defined as the axis along the tool string, the Y
29 axis is aligned along the toolface datum, and the .X
axis is oriented such that the X, Y and Z axes form 31 a set defining the directions of basis vectors to 1 define position of the tool with respect to the 2 earth's gravitational anal magnetic fields.
4 The output of the accelerometer is expressed as a gravity function Gf, having components G,~, G~, and GZ
6 in the frame of reference. Gf is defined by:
- sin(Il~IC)sin(G'~I'F7 8 gf(Cat, GTF,IlI~C) = Gt - sin(INC)c~s((~'TF) Eqn 1 cos(I1~1C) where Gt is the vector sum of the total gravity 11 field, INC is the angle of inclination of the Z axis 12 from the vertical, and GTF is a parameter called the 13 Gravity Tool Face, defined as the angle between the 14 Y axis and the projection of the earth's gravitational field vector onto the X-Y plane.
17 GTF is equivalent to the roll angle of the tool 18 where the reference point or scribe line is in line 19 with the Y-axis.
21 The output of the magnetometer is expressed as a 22 magnetic function Hf, having components HX, Hy, and 23 HZ in the frame of reference. Hf is defined by 24 equation 2, which is attached as an appendix to this description.
27 In equation 2, Ht is the vector sum of the total 28 magnetic field, A~ is the magnetic azimuth relative 29 to magnetic north, and DIP is the angle down to the 1 earth's magnetic field vector from its projection on 2 the horizontal azimuth.
4 The above outputs can be algebraically manipulated
5 to obtain measurements that correspond to the
6 rotational position of the rotating shaft 20.
7
8 The first of these is the accelerometer toolface, or
9 ATF. This has the same definition as the variable GTF as defined alcove, and is defined as the 11 arctangent of (GX/Gy) .
13 The second of these measurements is the magnetic 14 toolface, or MTF. This is defined as the angle between the HY axis and the projection of the 16 earth's magnetic field vector onto the X-Y plane.
17 In a manner similar to ATF, MTF is measured with the 18 HY axis aligned to the scribe line. MTF is defined 19 as being the arctangent of (HX/HY) .
21 The final of these parameters is the toolface 22 azimuth, MTA. This is the angle between the North 23 axis and the projection of the tool's Y-axis onto 24 the N-E plane, i.e. MTA is the direction that the scribe line is pointing to in terms of the azimuth.
26 MTA is defined by:
28 MTA= (Gxy'Hz + Gz*Hx) *SQR.T (Gx*Gx + Gy*Gy +
29 Gz='Gz) / (Hy* (Gxz°Gx + Gz*Gz) + GyJ~ (Gz*Hz-Gx~cHx) .
(eqn. 3) 1 It will be apparent to those skilled in the art that 2 as an alternative to measuring the magnetic field 3 vectors, gyroscopic instruments could be used to 4 measure earth's rotation vectors , and, using similar transforms, angular measurements based on 6 inertial measurements could be made. Both these 7 methods, or any other suitable method for 8 determining the orientateon of the rotating shaft, 9 are incorporated within the scope of the present invention.
12 Fig. 2 shows the instrumentation used to convert the 13 raw data obtained from the accelerometer and 14 magnetometer into the form described above. As the shaft 20 is continuously rotating, the respective 16 toolface measurements will change depending on the 17 sampling frequency and rotational position of the 18 shaft 20.
When measuring and processing the signals from the 21 accelerometer and magnetometer, it is important that 22 the respective data input channels are phase matched 23 such that the measurement point in time for each 24 sample is the same. This can be achieved either through synchronous sampling or through calibration 26 of the system.
28 During drilling operations, in particular during 29 rotation, there is a trade-off between resolution of accelerometers and dynamic range. While rotating, 31 due to the accelerations observed the accelerometer 32 channels may saturate. This situation can, in 1 certain circumstances cause non liberties and errors 2 in the tool face or orientation calculation.
A method used to resolve this problem is to male per10d1.C: Statl.C: meaSUremellts of the Gx, Gy, G~ alld 6 Hx, Hy, H~ axis.
8 Using the static measured values, AG, IBC, DIP, GTF, 9 MTF, SLA and Ht can be calculated, where the term "SLA" is defined as MTA.
12 By geometric definition, and by examining equation 13 2, it is observed that AZ is the angle between GTF
14 and MTF. It is therefore concluded that by using the static measured AZ value and the MTF value obtained 16 dynamically while rotating, which is a magnetic 17 measurement and relatively immune to noise, 18 saturation and vibration effects, the GTF or desired 19 tool face orientation can. be measured using MTF
measurements.
22 The above is a valid approximation provided 23 substantial changes are not made between successive 24 static measurements, which is typically the case during the requisite operations.
27 The present invention uses the continuous sampling 28 of toolface information combined with a second 29 measurement to determine the position of the non-rotating sleeve.
1 The second measurement is provided by a signal 2 trigger means, at least one of which is provided at 3 a known location on each of the rotating drill shaft 4 and the offset stahiliser device.
6 In a first embodiment of the present invention, the 7 signal trigger means comprises apertures, which when aligned, define a through-passage that results in a 9 pressure pulse being generated.
11 In this embodiment, the non-rotating sleeve and 12 rotating shaft are designed such that each. has a 13 ehole through the sidewall. When the central shaft 14 20 rotates and the two holes line up, fluid or gas moves from the high-pressure centre bore to the 16 lower pressure outer bore. The effect of this fluid 17 or gas flow is to effect a negative pressure pulse 18 in the bore and a positive pulse in the annulus.
Fig. 3 shows this in more detail. A rotating 21 mandrel 60 has a pre-load ring 62 attached thereto 22 such that they rotate together. The device 30 23 comprising the non-rotating stabiliser is attached 24 to a borehole wall with knifed blades (not shown).
Apertures 64, 66, and 68 are provided in the 26 stabiliser device 30, the pre-load ring 62 and 27 mandrel 60 respectively.
29 The components illustrated in Fig. 3 are circular in cross-section.
1 The drillstring contains matter that is flowing 2 therein at a different pressure to the pressure of 3 the well-bore. The pressure of the drillstring is 4 normally higher than the pressure of the well-bore, such that when the orifice of the preload ring is 6 aligned with the orifice of the non-rotating 7 stabiliser, fluid passes from the tool out to the 8 well-bore, causing a negative pressure pulse in the 9 drill string.
11 It is to be understood that the detected pressure 12 pulse may also be either a negative or positive 13 pulse in the annulus or bore, or a combination of 14 such pulses.
16 A jet nozzle 70 is provided between the apertures 66 17 and 68 of the pre-load ring 62 and mandrel 60 to 18 help control the flow rate of matter between the 19 drillstring and the well-bore.
21 In a second embodiment of the present invention, the 22 signal trigger means comprises a striking member and 23 a resounding member, which when brought into 24 alignment cause an acoustic signal to be transmitted.
27 The non-rotating sleeve and rotating shaft are 28 designed such that one has a striking mechanism and 29 one has an activating mechanism such that when the central shaft rotates and the striking mechanism 31 lines up with the activation mechanism mechanical 32 energy is transferred causing the striking mechanism 1 to strike. The effect of this strike is to excite 2 an acoustic wave which travels up the device through 3 the drillstring to the detection device further up 4 in the drill string.
6 A number of features of the invention will now be 7 described, which are applicable to both embodiments 8 unless otherwise stated.
13 The second of these measurements is the magnetic 14 toolface, or MTF. This is defined as the angle between the HY axis and the projection of the 16 earth's magnetic field vector onto the X-Y plane.
17 In a manner similar to ATF, MTF is measured with the 18 HY axis aligned to the scribe line. MTF is defined 19 as being the arctangent of (HX/HY) .
21 The final of these parameters is the toolface 22 azimuth, MTA. This is the angle between the North 23 axis and the projection of the tool's Y-axis onto 24 the N-E plane, i.e. MTA is the direction that the scribe line is pointing to in terms of the azimuth.
26 MTA is defined by:
28 MTA= (Gxy'Hz + Gz*Hx) *SQR.T (Gx*Gx + Gy*Gy +
29 Gz='Gz) / (Hy* (Gxz°Gx + Gz*Gz) + GyJ~ (Gz*Hz-Gx~cHx) .
(eqn. 3) 1 It will be apparent to those skilled in the art that 2 as an alternative to measuring the magnetic field 3 vectors, gyroscopic instruments could be used to 4 measure earth's rotation vectors , and, using similar transforms, angular measurements based on 6 inertial measurements could be made. Both these 7 methods, or any other suitable method for 8 determining the orientateon of the rotating shaft, 9 are incorporated within the scope of the present invention.
12 Fig. 2 shows the instrumentation used to convert the 13 raw data obtained from the accelerometer and 14 magnetometer into the form described above. As the shaft 20 is continuously rotating, the respective 16 toolface measurements will change depending on the 17 sampling frequency and rotational position of the 18 shaft 20.
When measuring and processing the signals from the 21 accelerometer and magnetometer, it is important that 22 the respective data input channels are phase matched 23 such that the measurement point in time for each 24 sample is the same. This can be achieved either through synchronous sampling or through calibration 26 of the system.
28 During drilling operations, in particular during 29 rotation, there is a trade-off between resolution of accelerometers and dynamic range. While rotating, 31 due to the accelerations observed the accelerometer 32 channels may saturate. This situation can, in 1 certain circumstances cause non liberties and errors 2 in the tool face or orientation calculation.
A method used to resolve this problem is to male per10d1.C: Statl.C: meaSUremellts of the Gx, Gy, G~ alld 6 Hx, Hy, H~ axis.
8 Using the static measured values, AG, IBC, DIP, GTF, 9 MTF, SLA and Ht can be calculated, where the term "SLA" is defined as MTA.
12 By geometric definition, and by examining equation 13 2, it is observed that AZ is the angle between GTF
14 and MTF. It is therefore concluded that by using the static measured AZ value and the MTF value obtained 16 dynamically while rotating, which is a magnetic 17 measurement and relatively immune to noise, 18 saturation and vibration effects, the GTF or desired 19 tool face orientation can. be measured using MTF
measurements.
22 The above is a valid approximation provided 23 substantial changes are not made between successive 24 static measurements, which is typically the case during the requisite operations.
27 The present invention uses the continuous sampling 28 of toolface information combined with a second 29 measurement to determine the position of the non-rotating sleeve.
1 The second measurement is provided by a signal 2 trigger means, at least one of which is provided at 3 a known location on each of the rotating drill shaft 4 and the offset stahiliser device.
6 In a first embodiment of the present invention, the 7 signal trigger means comprises apertures, which when aligned, define a through-passage that results in a 9 pressure pulse being generated.
11 In this embodiment, the non-rotating sleeve and 12 rotating shaft are designed such that each. has a 13 ehole through the sidewall. When the central shaft 14 20 rotates and the two holes line up, fluid or gas moves from the high-pressure centre bore to the 16 lower pressure outer bore. The effect of this fluid 17 or gas flow is to effect a negative pressure pulse 18 in the bore and a positive pulse in the annulus.
Fig. 3 shows this in more detail. A rotating 21 mandrel 60 has a pre-load ring 62 attached thereto 22 such that they rotate together. The device 30 23 comprising the non-rotating stabiliser is attached 24 to a borehole wall with knifed blades (not shown).
Apertures 64, 66, and 68 are provided in the 26 stabiliser device 30, the pre-load ring 62 and 27 mandrel 60 respectively.
29 The components illustrated in Fig. 3 are circular in cross-section.
1 The drillstring contains matter that is flowing 2 therein at a different pressure to the pressure of 3 the well-bore. The pressure of the drillstring is 4 normally higher than the pressure of the well-bore, such that when the orifice of the preload ring is 6 aligned with the orifice of the non-rotating 7 stabiliser, fluid passes from the tool out to the 8 well-bore, causing a negative pressure pulse in the 9 drill string.
11 It is to be understood that the detected pressure 12 pulse may also be either a negative or positive 13 pulse in the annulus or bore, or a combination of 14 such pulses.
16 A jet nozzle 70 is provided between the apertures 66 17 and 68 of the pre-load ring 62 and mandrel 60 to 18 help control the flow rate of matter between the 19 drillstring and the well-bore.
21 In a second embodiment of the present invention, the 22 signal trigger means comprises a striking member and 23 a resounding member, which when brought into 24 alignment cause an acoustic signal to be transmitted.
27 The non-rotating sleeve and rotating shaft are 28 designed such that one has a striking mechanism and 29 one has an activating mechanism such that when the central shaft rotates and the striking mechanism 31 lines up with the activation mechanism mechanical 32 energy is transferred causing the striking mechanism 1 to strike. The effect of this strike is to excite 2 an acoustic wave which travels up the device through 3 the drillstring to the detection device further up 4 in the drill string.
6 A number of features of the invention will now be 7 described, which are applicable to both embodiments 8 unless otherwise stated.
10 The generated signal, hereinafter referred to
11 generally as a pulse, is detected by a pressure
12 sensor or an acoustic sensor, which in a preferred
13 embodiment of the invention is located in the centre
14 of the rotating shaft, although it will be appreciated that the pressure or acoustic sensor 16 could be located in any suitable location either in 17 the bore of the central shaft 20 or the annulus of 18 the offset device 30. In the first embodiment, a 19 strain gauge sensor could be used rather than a pressure sensor.
22 The pressure or acoustic signal is fed out through 23 an exit port, which can utilise different shaped 24 plates or covers so that the system is customised for different users. Changing the profile of the 26 exit port will result in the compression or 27 extension of the pressure or acoustic signal, and a 28 user's software and. acoustic signal or pressure 29 detection routines can be adjusted as such after simple flow loop testing using various exit port 31 profiles.
1 The pulse is used to synchronise or to trigger the 2 sampling of the instrumentation system such that the 3 appropriate rotational toolface measurement 4 described above is identified and the poslti.oll of the non-rotating sleeve determined.
7 The signal trigger means are at l~nown locations on 8 the rotating shaft 20 and on the stabiliser device 9 30, and so when the orientation of the shaft 20 is detected at the time of the pressure or acoustic 11 pulse, this can be used to infer the orientation of 12 the stabiliser device 30.
14 The accuracy of the measured tool face position can be increased by taking averages of the calculated 16 position synchronised with pressure or acoustic 17 pulses over a period of time.
19 Further techniques that can be used to increase the accuracy of the measured tool face position include 21 using a Kalman Filtering technique or other 22 associated Least Squares error technique to 23 determine position and establish positional movement 24 trends.
26 Furthermore, more than one set of corresponding 27 apertures can be provided, so that more than one 28 pulse is generated per revolution of the shaft. The 29 data generated by these extra pulses helps decrease the errors in reading the signals.
1 Referring to Fig. 2, the inputs 40 representing each 2 component of the outputs from the accelerometer and 3 magnetometer, together with inputs 42 representing 4 around and 44 represe11t1nc~ temperature, are fed unto a low pass filter 46 before being passed on to a 6 first analogue to digital converter 48. Outputs 50, 7 52 from pressure or acoustic signal sensors 8 (described Iaelow) are input into a second analogue 9 to digital converter 54. Outputs from both the A-D
converters 48, 54 are input to a processor 56, which 11 produces an output 58.
13 Instead of using a low pass filter, a A-D convertor 14 and zero phase digital filter could be used.
16 The output 58 shows the relevant angles, pressure 17 signals, and synchronises the angle measurements 18 with the pressure or acoustic measurements.
As with any hydraulic system, noise or erratic 21 pulses are present. The particular pulse generated 22 by the alignment of the two signal triggers is 23 modelled and determined using a correlation 24 detection technique that uses prior knowledge of the pulse shape and profile along with data from the 26 instrumentation, in order to correct for the 27 rotational speed of the drillpipe. The measured 28 pulse is correlated with a confidence level to the 29 expected measurement and a probability measure estimated and used in performance enhancement.
1 Using this method means that a single set of 2 instrumentation can be adapted to be used for many 3 different orientation systems or remote signalling 4 systems and with the correlation detection system used to discriminate which measurement applies to 6 which signal, the result is that a plethora of 7 devices can be used for measuring and signalling to 8 the remote instrumentation if required.
The present invention can not only be used for 11 drilling systems, it has applications for 12 determining the position of casing outlets in 13 multilateral systems and for orienting completion 14 systems in a number of downhole applications. The present invention can be applied to bottom hole 16 assemblies whether comprised of drill collars and 17 traditional components as well as to drilling 18 assemblies comprised of casing, tubulars, or any 19 combination of casing and downhole drilling collars or tools.
22 Yet another application of this invention is that 23 the downhole rate of rotation of the moveable member 24 can be determined by measuring the frequency of the pulses that are generated. This can be calculated 26 at the downhole tool and transmitted uphole, or a 27 surface system could monitor the pulses and derive 28 the downhole FtPNi therefrom.
The angular position and the rate of change of 31 angular position can be utilised in a servo, 32 actuation or control feedback arrangement whereby a 1 system drives the offset sleeve counter clockwise to 2 retain a predetermined position, most suitably at a 3 rate determined from the measurement.
Furthermore, differentiation of the rate measurement 6 yields information relating to acceleration aspects 7 of the moveable member. Both these measurements 8 provide valuable information relating to movement of 9 the non rotating sleeve and information relating to how efficiently the rotating member is moving in the 11 borehole and if sticking and slipping of the bit and 12 rotating member is a problem. For example a 13 downhole sample with wide distribution would be 14 indicative of stick slip. Changes in rotary RPM, weight, or mud additives might be employed to 16 eliminate this destructive condition.
18 In the first embodiment, the use of the pressure 19 measurements in both the bore and in the annulus can greatly improve the performance of the system in 21 terms of signal to noise ratio. In particular, 22 performing a bore annulus differential measurement 23 can yield an improved signal to noise ratio.
Additionally, noise generated by a second pulsing 26 system used for example to transmit data to the 27 surface can be subtracted from the signal received 28 at the detection system by using a common 29 microcontroller or DSP to control both systems and having knowledge when pulsing to the surface is 31 taleing place. Additionally the correlation methods l described previously can be used to discriminate 2 between the various pulse types.
4 In a still further aspect of the invention, the exit 5 port pressure pulse (or acoustic signal) and either 6 of the bore or annular pressure transducer (or 7 acoustic sensor) can be used to send data from the 8 surface to the down hole tool.
10 This is achieved in a number of possible ways.
11 Firstly the drill string rotation can be modulated.
12 Altering the drill string RPM changes the pulse 13 frequency and by sending a pre-determined sequence a 14 message can be transferred from the surface to a
22 The pressure or acoustic signal is fed out through 23 an exit port, which can utilise different shaped 24 plates or covers so that the system is customised for different users. Changing the profile of the 26 exit port will result in the compression or 27 extension of the pressure or acoustic signal, and a 28 user's software and. acoustic signal or pressure 29 detection routines can be adjusted as such after simple flow loop testing using various exit port 31 profiles.
1 The pulse is used to synchronise or to trigger the 2 sampling of the instrumentation system such that the 3 appropriate rotational toolface measurement 4 described above is identified and the poslti.oll of the non-rotating sleeve determined.
7 The signal trigger means are at l~nown locations on 8 the rotating shaft 20 and on the stabiliser device 9 30, and so when the orientation of the shaft 20 is detected at the time of the pressure or acoustic 11 pulse, this can be used to infer the orientation of 12 the stabiliser device 30.
14 The accuracy of the measured tool face position can be increased by taking averages of the calculated 16 position synchronised with pressure or acoustic 17 pulses over a period of time.
19 Further techniques that can be used to increase the accuracy of the measured tool face position include 21 using a Kalman Filtering technique or other 22 associated Least Squares error technique to 23 determine position and establish positional movement 24 trends.
26 Furthermore, more than one set of corresponding 27 apertures can be provided, so that more than one 28 pulse is generated per revolution of the shaft. The 29 data generated by these extra pulses helps decrease the errors in reading the signals.
1 Referring to Fig. 2, the inputs 40 representing each 2 component of the outputs from the accelerometer and 3 magnetometer, together with inputs 42 representing 4 around and 44 represe11t1nc~ temperature, are fed unto a low pass filter 46 before being passed on to a 6 first analogue to digital converter 48. Outputs 50, 7 52 from pressure or acoustic signal sensors 8 (described Iaelow) are input into a second analogue 9 to digital converter 54. Outputs from both the A-D
converters 48, 54 are input to a processor 56, which 11 produces an output 58.
13 Instead of using a low pass filter, a A-D convertor 14 and zero phase digital filter could be used.
16 The output 58 shows the relevant angles, pressure 17 signals, and synchronises the angle measurements 18 with the pressure or acoustic measurements.
As with any hydraulic system, noise or erratic 21 pulses are present. The particular pulse generated 22 by the alignment of the two signal triggers is 23 modelled and determined using a correlation 24 detection technique that uses prior knowledge of the pulse shape and profile along with data from the 26 instrumentation, in order to correct for the 27 rotational speed of the drillpipe. The measured 28 pulse is correlated with a confidence level to the 29 expected measurement and a probability measure estimated and used in performance enhancement.
1 Using this method means that a single set of 2 instrumentation can be adapted to be used for many 3 different orientation systems or remote signalling 4 systems and with the correlation detection system used to discriminate which measurement applies to 6 which signal, the result is that a plethora of 7 devices can be used for measuring and signalling to 8 the remote instrumentation if required.
The present invention can not only be used for 11 drilling systems, it has applications for 12 determining the position of casing outlets in 13 multilateral systems and for orienting completion 14 systems in a number of downhole applications. The present invention can be applied to bottom hole 16 assemblies whether comprised of drill collars and 17 traditional components as well as to drilling 18 assemblies comprised of casing, tubulars, or any 19 combination of casing and downhole drilling collars or tools.
22 Yet another application of this invention is that 23 the downhole rate of rotation of the moveable member 24 can be determined by measuring the frequency of the pulses that are generated. This can be calculated 26 at the downhole tool and transmitted uphole, or a 27 surface system could monitor the pulses and derive 28 the downhole FtPNi therefrom.
The angular position and the rate of change of 31 angular position can be utilised in a servo, 32 actuation or control feedback arrangement whereby a 1 system drives the offset sleeve counter clockwise to 2 retain a predetermined position, most suitably at a 3 rate determined from the measurement.
Furthermore, differentiation of the rate measurement 6 yields information relating to acceleration aspects 7 of the moveable member. Both these measurements 8 provide valuable information relating to movement of 9 the non rotating sleeve and information relating to how efficiently the rotating member is moving in the 11 borehole and if sticking and slipping of the bit and 12 rotating member is a problem. For example a 13 downhole sample with wide distribution would be 14 indicative of stick slip. Changes in rotary RPM, weight, or mud additives might be employed to 16 eliminate this destructive condition.
18 In the first embodiment, the use of the pressure 19 measurements in both the bore and in the annulus can greatly improve the performance of the system in 21 terms of signal to noise ratio. In particular, 22 performing a bore annulus differential measurement 23 can yield an improved signal to noise ratio.
Additionally, noise generated by a second pulsing 26 system used for example to transmit data to the 27 surface can be subtracted from the signal received 28 at the detection system by using a common 29 microcontroller or DSP to control both systems and having knowledge when pulsing to the surface is 31 taleing place. Additionally the correlation methods l described previously can be used to discriminate 2 between the various pulse types.
4 In a still further aspect of the invention, the exit 5 port pressure pulse (or acoustic signal) and either 6 of the bore or annular pressure transducer (or 7 acoustic sensor) can be used to send data from the 8 surface to the down hole tool.
10 This is achieved in a number of possible ways.
11 Firstly the drill string rotation can be modulated.
12 Altering the drill string RPM changes the pulse 13 frequency and by sending a pre-determined sequence a 14 message can be transferred from the surface to a
15 down hole tool.
16
17 With respect to the first embodiment; at a given
18 flow rate there will be a known pressure drop below
19 the tool and therefore a known exit port pulse height. By varying the flow rate this pulse height 21 will change, for example a 25o change in flow rate 22 would generate a similar change in pressure pulse 23 height. By cycling the pumps at surface in a 24 predetermined sequence an encoded message can be transmitted to the down hole system.
27 This form of down linking (in either embodiment) 28 could be used, for example, to instruct the tool to 29 retract its angled blades, thus negating the eccentric effect of the offset sleeve and facilitate 31 drilling a non-curved borehole.
1 The invention also enables a deflection device to be 2 constructed, which comprises a decoupling device 3 which in one configuration could be a knuckle or 4 ball joint assembly, a deCentring device which in one form could be an eccentric stabilizer, combined 6 with a downhole power system which in one form would 7 be a mud motor. These elements combined would 8 result in a deflection device which would work while 9 the entire device is rotated. This combination would allow the pipe to be rotated while making hole 11 azimuth or inclination changes. This rotation 12 improves hole cleaning by assisting in keeping the 13 cuttings from the drilling operation in suspension 14 and by minimizing well bore wall friction acting on the drilling string, these effects improve drilling 16 efficiencies. These elements can be attached 17 directly to the motor or its elements or can be more 18 remotely connected as may be the case where the 19 drilling string may be casing and the motor would be housed within the casing above the rotary deflection 21 device which may be positioned closer to the bit.
23 It is also found that spectral analysis of the 24 pressure pulse waveforms measured in the bore and in the annulus yields information relating to the gas 26 content of the respective fluids. Typically, if the 27 gas content is high the effect is to attenuate and 28 slow down high frequencies, performing a spectral 29 analysis of the bore and annular pressure pulse signals and comparing the spectral amplitudes will 31 yield information relating to the Change in gas or 32 air content. This additional information can be 1 used as a quantitative measure of gas influx into 2 the wellbore and be used as a wellbore control 3 measurement.
~ further method to improve the signal detection in the first embodiment is to use a bore to annulus 7 differential pressure sensor. This enables a measurement of the pulse to me made without a high.
9 background hydrostatic pressure measurement.
11 Improvements and modifications can be made to the 12 above without departing from the scope of the 13 invention.
'~ b w H
C_5 U
N
..
U
~
N
o ~
0.
o , N '~
f~
-I-f-~' O
.
U
I
rw y.r O
~
1 ~
W i~
p v ~Y
q ..
b N o N
N
U
q II
-:
U
N
.~
r1 N M cti L(1 l0
27 This form of down linking (in either embodiment) 28 could be used, for example, to instruct the tool to 29 retract its angled blades, thus negating the eccentric effect of the offset sleeve and facilitate 31 drilling a non-curved borehole.
1 The invention also enables a deflection device to be 2 constructed, which comprises a decoupling device 3 which in one configuration could be a knuckle or 4 ball joint assembly, a deCentring device which in one form could be an eccentric stabilizer, combined 6 with a downhole power system which in one form would 7 be a mud motor. These elements combined would 8 result in a deflection device which would work while 9 the entire device is rotated. This combination would allow the pipe to be rotated while making hole 11 azimuth or inclination changes. This rotation 12 improves hole cleaning by assisting in keeping the 13 cuttings from the drilling operation in suspension 14 and by minimizing well bore wall friction acting on the drilling string, these effects improve drilling 16 efficiencies. These elements can be attached 17 directly to the motor or its elements or can be more 18 remotely connected as may be the case where the 19 drilling string may be casing and the motor would be housed within the casing above the rotary deflection 21 device which may be positioned closer to the bit.
23 It is also found that spectral analysis of the 24 pressure pulse waveforms measured in the bore and in the annulus yields information relating to the gas 26 content of the respective fluids. Typically, if the 27 gas content is high the effect is to attenuate and 28 slow down high frequencies, performing a spectral 29 analysis of the bore and annular pressure pulse signals and comparing the spectral amplitudes will 31 yield information relating to the Change in gas or 32 air content. This additional information can be 1 used as a quantitative measure of gas influx into 2 the wellbore and be used as a wellbore control 3 measurement.
~ further method to improve the signal detection in the first embodiment is to use a bore to annulus 7 differential pressure sensor. This enables a measurement of the pulse to me made without a high.
9 background hydrostatic pressure measurement.
11 Improvements and modifications can be made to the 12 above without departing from the scope of the 13 invention.
'~ b w H
C_5 U
N
..
U
~
N
o ~
0.
o , N '~
f~
-I-f-~' O
.
U
I
rw y.r O
~
1 ~
W i~
p v ~Y
q ..
b N o N
N
U
q II
-:
U
N
.~
r1 N M cti L(1 l0
Claims (49)
1. A downhole assembly comprising:
a device and a movable member capable of moving relative to the device;
orientation measurement means capable of obtaining a first set of readings representative of the orientation of the movable member; and at least one signal trigger means provided at a known location on each of the device and movable member to generate a signal upon alignment.
a device and a movable member capable of moving relative to the device;
orientation measurement means capable of obtaining a first set of readings representative of the orientation of the movable member; and at least one signal trigger means provided at a known location on each of the device and movable member to generate a signal upon alignment.
2. The assembly of claim 1, wherein the orientation measurement means comprises at least one angular measurement sensor.
3. The assembly of claim 2, wherein the angular measurement sensor is capable of calculating the orientation of the toolface of the movable member with respect to the earth's magnetic field components and/or the earth's gravity field components.
4. The assembly of any of claims 1-3, further comprising calculation means capable of determining the orientation of the device based on the time or frequency of the signal, the known locations of the signal trigger means, and the first set of readings.
5. The assembly of any of claims 1-4, wherein the device and the movable member comprise coaxial cylindrical portions which rotate relative to each other.
6. ~The assembly of any preceding claim, wherein a plurality of signal trigger means are provided on at least one of the movable member and device, such that a plurality of signals are generated by the signal trigger means upon movement of the movable member through part of or through a complete cycle.
7. The assembly of any preceding claim, further comprising a servo, actuation or control mechanism suitable to move the device to a predetermined orientation.
8. The assembly of any preceding claim, further comprising a deflection device which comprises a decoupling device, a decentering device, and a downhole power system.
9. The assembly of claim 8, wherein the decoupling device comprises a knuckle or ball joint assembly, the decentering device comprises an eccentric stabiliser, and the downhole system comprises a mud motor.
10. The assembly of any preceding Claim, wherein the movable member is a rotating drill shaft, and the device is an offset stabiliser device, and the assembly is a drillstring.
11. The assembly of any of claims 4-10, wherein the calculation means comprises electronic signal processing means comprising signal sampling means, signal digitising means, and a central processing unit or digital signal processor.
12. The assembly of claim 11, wherein the calculation means comprises a phase matched low pass filter or A-D convertor and zero phase digital filter.
13. The assembly of any preceding claim, wherein the signal generated comprises measurable changes in an electric current.
14. The assembly of any preceding claim, wherein the signal generated comprises measurable changes in a magnetic field.
15. The assembly of any of claims 1-12, wherein the signal trigger means comprises apertures at known points on each of the device and the movable member, such that upon alignment of the apertures, a through-passage is provided between a point outside the assembly and a point within the inner of the device or movable member, and the signal comprises a pressure pulse created by a pressure differential which acts to move a medium through the apertures.
16. The assembly of claim 15, wherein the medium comprises gas, fluid, drilling muds or similar matter.
17. The assembly of claim 15 or claim 16, further comprising a pressure sensor located in at least one of the device and the movable member.
18. The assembly of claim 17, wherein the pressure sensor comprises a bore pressure transducer.
19. The assembly of claim 17, wherein the pressure sensor comprises an annulus pressure transducer.
20. The assembly of any of claims 1-12, wherein the signal trigger means comprises a striking member provided at one of the movable member and the device, and a resounding member provided at the other of the movable member and the device, such that when the striking member and resounding member are brought into alignment, the signal generated comprises an acoustic signature.
21. The assembly of claim 20, further comprising a listening device suitable to detect the acoustic signature.
22. A method of determining the orientation of a downhole operations device, the device being part of an assembly which also comprises a movable member which moves relative to the device, and wherein each of the device and the movable member has at least one signal trigger means provided at a known location thereon, the method comprising the steps of;
determining the orientation of the movable member; and moving the movable member relative to the device, to generate a signal upon alignment of the signal trigger means.
determining the orientation of the movable member; and moving the movable member relative to the device, to generate a signal upon alignment of the signal trigger means.
23. The method of claim 22, wherein the step of determining the orientation of the movable member comprises using an accelerometer and a magnetometer.
24. The method of claim 23, comprising the step of using the accelerometer and magnetometer to calculate the orientation of the toolface of the movable member with respect to the earth's magnetic field vector and/or the earth's gravity vector.
25. The method of any of claims 22-24, further comprising determining the orientation of the device based on the time of the signal, the known locations of the signal trigger means, and the orientation of the movable member.
26. The method of any of claims 22-25, wherein the step of moving the movable member relative to the device comprises a rotation about a common axis.
27. The method of any of claims 22-26, further comprising the steps of providing a plurality of signal trigger means on at least one of the movable member and device, and generating a plurality of signals upon completion of one cycle of movement of the movable member.
28. The method of any of claims 22-27, further comprising the step of malting periodic static measurements of the gravity function and magnetic function, and using these static measurements for determining the orientation of the device in situations where data channels of the accelerometer or magnetometer are saturated.
29. The method of any of claims 22-28, further comprising the step of taking averages of the calculated position over time.
30. The method of any of claims 22-29, further comprising the step of applying a Kalman filtering technique or least squares error technique to determine positional trends of the device.
31. The method of any of claims 22-30, further comprising performing a correlation detection technique to remove noise from the detected signal.
32. The method of any of claims 22-31, further comprising using a servo mechanism to move the device to a predetermined orientation.
33. The method of any of claims 22-32, further comprising the step of deflecting a device using a decoupling device, a decentering device, and a downhole power system.
34. The method of claim 33, wherein the decoupling device comprises a knuckle, the decentering device comprises an eccentric stabiliser, and the downhole system comprises a mud motor.
35. The method of any of claims 22-34, wherein the movable member is a rotating drill shaft, and the device is an offset stabiliser device, and the assembly is a drillstring.
36. The method of any of claims 22-35, wherein the step of determining the orientation of the device comprises the steps of sampling and digitising the signal, and outputting the signal to a central processing unit or digital signal processor.
37. The method of claim 36, wherein the step of determining the orientation of the device further comprises passing the signal through a phase matched low pass filter before digitising and outputting the signal.
38. The method of any of claims 22-37, wherein the step of generating a signal comprises the step of changing an electric current.
39. The assembly of claims 22-38, wherein the step of generating a signal comprises the step of changing a magnetic field.
40. The method of any of claims 22-37, wherein the signal trigger means comprises apertures at known points on the surfaces of each of the device and the movable member, and wherein the step of moving the movable member relative to the device to generate a signal upon alignment of the signal trigger means comprises the step of;
bringing the apertures into alignment to provide a through-passage between a point outside the assembly and a point within the inner of the device or movable member, which generates a pressure pulse created by a pressure differential which acts to move a medium through the apertures.
bringing the apertures into alignment to provide a through-passage between a point outside the assembly and a point within the inner of the device or movable member, which generates a pressure pulse created by a pressure differential which acts to move a medium through the apertures.
41. The method of claim 40, wherein the medium comprises gas, fluid, drilling muds or similar matter.
42. The method of claim 40 or claim 41, further comprising the step of sensing pressure at a point in at least one of the device and the movable member.
43. The method of claim 42, wherein the pressure sensing step utilises a bore pressure transducer.
44. The method of claim 42, wherein the pressure sensing step utilises an annular pressure transducer.
45. The method of any of claims 40-44, further comprising the step of varying the flow rate down the drillstring to modify the magnitude of the generated pressure pulse.
46. The method of any of claims 40-44, further comprising the step of modulating the drillstring rotation to modify the magnitude of the generated pressure pulse.
47. The method of claim 45 or claim 46, further comprising the step of using the modified pressure pulse as a signal that is sent from a surface to a downhole operations tool.
48. The method of any of claims 22-37, wherein the signal trigger means comprises a striking member provided at one of the movable member and the device, and a resounding member provided at the other of the movable member and the device, and wherein the step of moving the movable member relative to the device to generate a signal upon alignment of the signal trigger means comprises the step of bringing the striking member and resounding member into alignment to generate an acoustic signature.
49. The method of claim 48, further comprising detecting the acoustic signature utilising a listening device.
Applications Claiming Priority (3)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| GB0305617A GB0305617D0 (en) | 2003-03-12 | 2003-03-12 | Determination of Device Orientation |
| GB0305617.3 | 2003-03-12 | ||
| PCT/GB2004/001087 WO2004081494A2 (en) | 2003-03-12 | 2004-03-12 | Determination of the orientation of a dowhole device |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA2518938A1 true CA2518938A1 (en) | 2004-09-23 |
Family
ID=9954602
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA002518938A Abandoned CA2518938A1 (en) | 2003-03-12 | 2004-03-12 | Determination of the orientation of a downhole device |
Country Status (7)
| Country | Link |
|---|---|
| EP (1) | EP1601857A2 (en) |
| AU (1) | AU2004219836A1 (en) |
| CA (1) | CA2518938A1 (en) |
| GB (1) | GB0305617D0 (en) |
| MX (1) | MXPA05009793A (en) |
| NO (1) | NO20054432L (en) |
| WO (1) | WO2004081494A2 (en) |
Families Citing this family (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US7609169B2 (en) | 2006-08-31 | 2009-10-27 | Precision Energy Services, Inc. | Electromagnetic telemetry apparatus and methods for minimizing cyclical or synchronous noise |
Family Cites Families (14)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US5150333A (en) * | 1977-12-05 | 1992-09-22 | Scherbatskoy Serge Alexander | Method and apparatus for providing improved pressure pulse characteristics for measuring while drilling |
| US4987684A (en) * | 1982-09-08 | 1991-01-29 | The United States Of America As Represented By The United States Department Of Energy | Wellbore inertial directional surveying system |
| DE3325962A1 (en) * | 1983-07-19 | 1985-01-31 | Bergwerksverband Gmbh, 4300 Essen | TARGET DRILL ROD FOR ROTATING DRILL ROD WITH RINSING CHANNEL FOR UNDERGROUND OPERATION |
| US4597067A (en) * | 1984-04-18 | 1986-06-24 | Conoco Inc. | Borehole monitoring device and method |
| US5220963A (en) * | 1989-12-22 | 1993-06-22 | Patton Consulting, Inc. | System for controlled drilling of boreholes along planned profile |
| US5259468A (en) * | 1990-10-04 | 1993-11-09 | Amoco Corporation | Method of dynamically monitoring the orientation of a curved drilling assembly and apparatus |
| US5410303A (en) * | 1991-05-15 | 1995-04-25 | Baroid Technology, Inc. | System for drilling deivated boreholes |
| US5283768A (en) * | 1991-06-14 | 1994-02-01 | Baker Hughes Incorporated | Borehole liquid acoustic wave transducer |
| US5682112A (en) * | 1994-05-18 | 1997-10-28 | Nec Corporation | Phase locked loop control apparatus |
| GB9507008D0 (en) * | 1995-04-05 | 1995-05-31 | Mcloughlin Stephen J | A downhole adjustable device for trajectory control in the drilling of deviated wells |
| US5924499A (en) * | 1997-04-21 | 1999-07-20 | Halliburton Energy Services, Inc. | Acoustic data link and formation property sensor for downhole MWD system |
| US6092610A (en) * | 1998-02-05 | 2000-07-25 | Schlumberger Technology Corporation | Actively controlled rotary steerable system and method for drilling wells |
| EP1192482A4 (en) * | 2000-05-08 | 2009-11-11 | Schlumberger Holdings | Digital signal receiver for measurement while drilling system having noise cancellation |
| US6381858B1 (en) * | 2000-09-22 | 2002-05-07 | Schlumberger Technology Corporation | Method for calculating gyroscopic wellbore surveys including correction for unexpected instrument movement |
-
2003
- 2003-03-12 GB GB0305617A patent/GB0305617D0/en not_active Ceased
-
2004
- 2004-03-12 EP EP04720082A patent/EP1601857A2/en not_active Withdrawn
- 2004-03-12 CA CA002518938A patent/CA2518938A1/en not_active Abandoned
- 2004-03-12 WO PCT/GB2004/001087 patent/WO2004081494A2/en not_active Application Discontinuation
- 2004-03-12 MX MXPA05009793A patent/MXPA05009793A/en not_active Application Discontinuation
- 2004-03-12 AU AU2004219836A patent/AU2004219836A1/en not_active Abandoned
-
2005
- 2005-09-26 NO NO20054432A patent/NO20054432L/en not_active Application Discontinuation
Also Published As
| Publication number | Publication date |
|---|---|
| WO2004081494A3 (en) | 2004-12-23 |
| NO20054432D0 (en) | 2005-09-26 |
| WO2004081494A2 (en) | 2004-09-23 |
| EP1601857A2 (en) | 2005-12-07 |
| GB0305617D0 (en) | 2003-04-16 |
| NO20054432L (en) | 2005-12-09 |
| MXPA05009793A (en) | 2006-07-03 |
| AU2004219836A1 (en) | 2004-09-23 |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| EP3312382B1 (en) | Device for measuring gravitational acceleration during state of spinning and extraction method | |
| US7260477B2 (en) | Estimation of borehole geometry parameters and lateral tool displacements | |
| US6742604B2 (en) | Rotary control of rotary steerables using servo-accelerometers | |
| US6816788B2 (en) | Inertially-stabilized magnetometer measuring apparatus for use in a borehole rotary environment | |
| Xue et al. | Continuous real-time measurement of drilling trajectory with new state-space models of Kalman filter | |
| US20060260843A1 (en) | Methods and systems for determining angular orientation of a drill string | |
| US20030085059A1 (en) | Relative drill bit direction measurement | |
| EP3263832A1 (en) | Method and device for depth positioning downhole tool and associated measurement log of a hydrocarbon well | |
| GB2481495A (en) | Real time determination of casing location and distance from tilted antenna measurement | |
| Jurkov et al. | Experimental feasibility of the in-drilling alignment method for inertial navigation in measurement-while-drilling | |
| AU2010256915A1 (en) | Downhole magnetic measurement while rotating and methods of use | |
| CN108387205A (en) | The measurement method of drilling tool attitude measurement system based on Fusion | |
| CA2938657C (en) | Method and apparatus for continuous wellbore curvature orientation and amplitude measurement using drill string bending | |
| CA2440907C (en) | Borehole surveying | |
| CA2518938A1 (en) | Determination of the orientation of a downhole device | |
| CA3082468C (en) | Azimuth determination while rotating | |
| AU2013206535A1 (en) | Real-time casing detection using tilted and crossed antenna measurement | |
| GB2603081A (en) | Azimuth determination while rotating | |
| Yiyong et al. | Control unit of the directional drilling system |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| FZDE | Discontinued |