DK179179B1 - System and method for transmission of pulses - Google Patents
System and method for transmission of pulses Download PDFInfo
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- DK179179B1 DK179179B1 DKPA201670742A DKPA201670742A DK179179B1 DK 179179 B1 DK179179 B1 DK 179179B1 DK PA201670742 A DKPA201670742 A DK PA201670742A DK PA201670742 A DKPA201670742 A DK PA201670742A DK 179179 B1 DK179179 B1 DK 179179B1
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- pulse
- control parameter
- pulsating signal
- borehole
- tool
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- 238000000034 method Methods 0.000 title claims abstract description 44
- 230000005540 biological transmission Effects 0.000 title description 12
- 238000005553 drilling Methods 0.000 claims abstract description 46
- 239000012530 fluid Substances 0.000 claims abstract description 35
- 238000005259 measurement Methods 0.000 claims abstract description 33
- 238000012544 monitoring process Methods 0.000 claims abstract description 17
- 238000012360 testing method Methods 0.000 claims abstract description 11
- 238000005086 pumping Methods 0.000 claims description 28
- 230000006870 function Effects 0.000 claims description 13
- 230000003213 activating effect Effects 0.000 claims description 2
- 230000008439 repair process Effects 0.000 claims 1
- 239000000779 smoke Substances 0.000 claims 1
- 230000004913 activation Effects 0.000 description 17
- 238000009434 installation Methods 0.000 description 7
- 239000011435 rock Substances 0.000 description 5
- 230000015572 biosynthetic process Effects 0.000 description 4
- 238000005755 formation reaction Methods 0.000 description 4
- 230000033001 locomotion Effects 0.000 description 3
- 230000035939 shock Effects 0.000 description 3
- 230000026058 directional locomotion Effects 0.000 description 2
- 230000008569 process Effects 0.000 description 2
- 238000012549 training Methods 0.000 description 2
- 238000004891 communication Methods 0.000 description 1
- 238000013461 design Methods 0.000 description 1
- 238000001514 detection method Methods 0.000 description 1
- 238000005265 energy consumption Methods 0.000 description 1
- 230000007246 mechanism Effects 0.000 description 1
- 239000002245 particle Substances 0.000 description 1
- 230000000750 progressive effect Effects 0.000 description 1
- 230000010349 pulsation Effects 0.000 description 1
- 230000002285 radioactive effect Effects 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 230000008054 signal transmission Effects 0.000 description 1
Classifications
-
- 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
- E21B47/14—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 using acoustic waves
- E21B47/18—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 using acoustic waves through the well fluid, e.g. mud pressure pulse telemetry
-
- 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
- E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
- E21B21/08—Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
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- Engineering & Computer Science (AREA)
- Life Sciences & Earth Sciences (AREA)
- Mining & Mineral Resources (AREA)
- Geology (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Geophysics (AREA)
- Remote Sensing (AREA)
- Acoustics & Sound (AREA)
- Mechanical Engineering (AREA)
- Geophysics And Detection Of Objects (AREA)
Abstract
The invention relates to a method and a system for monitoring one or more control parameters in a borehole, wherein a downhole tool is mounted in a drill string and is able to measure at least one control parameter using suitable sensor units. The down- hole tool generates at least one pulsating signal based on the measurements, wherein this pulsating signal comprises a single pulse where the pulse length is determined as function of the value of the measured control parameter. The pulse length may further be determined using a selected resolution for that control parameter. The pulsating signal is then transmitted to ground level via the drilling fluid where it can be read by simply monitoring the pump pressure. A simple test can be performed before starting the operation of the drill string.
Description
<1θ> DANMARK (10)
<12> PATENTSKRIFT
Patent- og
Varemærkestyrelsen (51) lnt.CI.: E 21 B 47/18 (2012.01) E 21 B 44/06 (2006.01) H 03 K 7/08(2006.01)
H 03 M 5/08(2006.01) G 01 V 1/46(2006.01) (21) Ansøgningsnummer: PA 2016 70742 (22) Indleveringsdato: 2016-09-21 (24) Løbedag: 2016-09-21 (41) Aim. tilgængelig: 2018-01-15 (45) Patentets meddelelse bkg. den: 2018-01-15 (73) Patenthaver: Advancetech ApS, Østervangsvej 41,6715 Esbjerg N, Danmark (72) Opfinder: Sigurd Solem, Vilslevvej 68, 6771 Gredstedbro, Danmark (74) Fuldmægtig: Patrade A/S, Fredens Torv 3A, 8000 Århus C, Danmark (54) Benævnelse: System and method for transmission of pulses (56) Fremdragne publikationer:
US 2008/0068210 A1 US 4,866,680 A US 2009/0120689 A1 (57) Sammendrag:
The invention relates to a method and a system for monitoring one or more control parameters in a borehole, wherein a downhole tool is mounted in a drill string and is able to measure at least one control parameter using suitable sensor units. The down- hole tool generates at least one pulsating signal based on the measurements, wherein this pulsating signal comprises a single pulse where the pulse length is determined as function of the value of the measured control parameter. The pulse length may further be determined using a selected resolution for that control parameter. The pulsating signal is then transmitted to ground level via the drilling fluid where it can be read by simply monitoring the pump pressure. A simple test can be performed before starting the operation of the drill string.
Fortsættes ...
Pressure
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Fig i
Method for transmission of pulses and a system thereof
Field of the Invention
The present invention relates to a method for monitoring one or more control parameters in a borehole, wherein the method comprises the steps of operating a drill string with at least one downhole tool in the borehole, generating at least one pulsating signal via the at least one downhole tool, and transmitting the at least one pulsating signal to a ground level.
The present invention also relates to a system for monitoring one or more control parameters in a borehole, comprising a drill string with at least one downhole tool positioned in the borehole and an operating system located at a ground level, wherein the operating system is configured to operate the drill string in the borehole, the at least one downhole tool is configured to generate at least one pulsating signal and to transmit said at least one pulsating signal to the ground level.
Background of the Invention
It is well known to use drift indicator systems for keeping track of the direction of drilling in vertical or near vertical boreholes. Drift indicator tools are mounted in the drill string, normally behind or near the drill bit, and are in communication with a surface system. A pure mechanical drift indicator is the Teledrift tool™, partly disclosed in GB 2157345 A, comprising a movable pendulum and a series of seven shoulders, wherein a spring biases the pendulum along the series of shoulders when the pumping and rotation are stopped. This drift indicator tool produces a pulsating signal containing a maximum of seven mud pulses indicating a maximum indication angle of 7 degrees or 3.5 degrees. The pulsating signal is detected and decoded either manually or by a surface recorder at ground level.
However, this drift indicator system provides limited inclination data and cannot be used to detect other type of data. Secondly, a number of drift indicator systems have to be installed by specialised technicians and require suitable training of the rig personnel in order to operate this drift indicator system.
Measurement while drilling with (MWD) systems can also be used to survey the drilling process, where the MWD tool provides indication data, direction data and other data. The MWD tool requires a complex transmission system in order to generate encoded pulse signals which are then transmitted to a surface decoder system having an advanced user interface. The surface decoder system is normally mounted on a rig floor and requires expert installation and ATEX certification. This increases the installation and operation costs as specialised engineers or technicians are required to install and operate the MWD system.
US 2008/068210 A1 describes a method that determines a drilling event, in particular when a mud pump is off. A first sensor (pressure sensor) measures a first signal (pressure) over a first selected time interval. Another signal, in this case noise, is detected by a second sensor over another time interval. The aim is to determine if there is noise reduction in the second signal. The first signal is transformed into a frequency domain. An event from the mud pump is detected whether the pump is on, based on a power signal at an operating frequency. Another event like flow/no flow in the borehole is also detected with an apparatus comprising at least one pressure sensor and a shock sensor. The pressure sensor can measure the hydraulic noise level and determine whether the mud pumps are on or off.
US 4866680 A describes another system and a method of providing signals to ground level via a data link (electric) when measuring on a down hole drilling apparatus. Data is mainly provided to the surface via a data link, but the system can also provide mud pulses in parallel to the data link. The mud pulse signal transmission includes generation of shock wave mud pulses as short shock waves via a fast opening/closing valve, resulting in a “binary” signal where one or more pulses correspond to one cipher in a value from a sensor. Thus, a number of these mud pulses are needed to indicate one reading from a sensor. This requires complicated decoding systems on ground level, resulting in expensive equipment, that further needs to fulfil the Atex requirements.
Until now, the main design purpose of the telemetry industry has been to transmit mud pulse signals as fast as possible and encode these mud pulses with as much data as possible. This has been achieved by increasing the transmission frequency and, thus, keeping the pulse or bit length as short as possible. Furthermore, multiple amplitude or bit heights are used to encode additional data into each pulse signal. In addition, varying the pulse or bit length, and thus the frequency thereof, is also used to generate complex pulse signals.
There is thus need for a cheap and simple downhole tool that can be operated and installed without the use of engineers or technicians.
Object of the Invention
An object of the invention is to provide a method and a system that solves the abovementioned problems.
Another object of the invention is to provide a method and a system that has a simple and cheap transmission mechanism.
Yet another object of the invention is to provide a method and a system that allows for a fast and accurate activation of the downhole tool.
An object of the invention is to provide a method and a system that can be installed and operated without the use of a surface decoding system and without additional training of the rig personnel.
Description of the Invention
An object of the invention is achieved by a method for monitoring one or more control parameters in a borehole, comprising the following steps:
operating a drill string with at least one downhole tool in the borehole, detecting an event, e.g. when pumping is stopped, measuring at least a first control parameter, generating at least one pulsating signal via the at least one downhole tool, the at least one pulsating signal comprising a value of the first control parameter, transmitting the at least one pulsating signal to a ground level, e.g. after pumping is restarted, wherein the at least one pulsating signal comprises a single pulse having a predetermined pulse amplitude, wherein the pulse length is determined as function of the value of the first control parameter.
This provides a simple and cheap method for surveying the directional movement of a drill string during drilling applications, which does not require a complex surface decoder system or ATEX certification for operating the downhole tool. Furthermore, no complex transmission systems are required in order to transmit the pulsating signals from the downhole tool to ground level. This significantly reduces the installation and operation costs compared to conventional survey methods.
This method can suitably be used in any applications, particularly drilling applications, in vertical or deviated boreholes where directional survey measurements are desired. The present system can suitably be used on rigs located at ground level, or at sea level, where no specialised engineers or technicians are present. This allows the downhole tool to be simply picked up and mounted in the drill string without additional calibration and setup procedures.
The present method allows the pulsating signal to be defined by a single pulse having a variable pulse length determined as function of the value of the control parameter. This single pulse further has a substantially constant pulse height or amplitude. No frequency modulation and no amplitude modulations are needed to encode data into the pulsating signal. Each pulsating signal comprises a single data set, whereas some conventional survey methods encode multiple data sets into the same pulsating signal.
According to the invention, the method and the corresponding system (the latter is discussed further below) is further special in that, said single pulse comprises a first pulse section having a constant pulse length and a second pulse section having a variable pulse length, wherein said variable pulse length is determined as function of the value of the first control parameter.
The single pulse defining the pulsating signal may comprise a first pulse section and a second pulse section, which combined define the pulse length of the pulsating signal. The first pulse section may indicate the start of the pulsating signal and have a predetermined constant pulse length. This constant pulse length may in example, but not limited to, be between 0 seconds and 20 seconds. The first pulse section may indicate the measured value of the control parameter and have a variable pulse length. This allows the measured control parameter to be encoded by simply varying the total pulse length of the pulsating signal. This encoded pulsating signal can thus be detected by a simple receiver or a pressure transducer/gauge at ground level, wherein the detected pulse length can be transformed into a representative value of the control parameter, e.g. using a simple look-up table.
The pulse length of this second pulse section may vary between a minimum pulse length defining a minimum value of the control parameter and a maximum pulse length defining a maximum value of the control parameter. In example, but not limited to, the minimum pulse length may be zero. The maximum pulse length may suitably be selected according to the measured type of control parameter, thus different types of control parameters may have different or same pulse length ranges. In example, but not limited to, the minimum pulse length may be selected between 5 seconds and 480 seconds. This allows for a greater measuring range than conventional drift indicators, such as the tool disclosed in GB 2157345 A. This also allows for an easy detection unlike some MWD tool which require very fast and accurate receivers in order to properly detect the amplitude and/or frequency modulated signal.
According to one embodiment, the at least one pulsating signal has a predetermined resolution which is determined based on a maximum value of said first control parameter, wherein said pulse length or variable pulse length is determined based on said predetermined resolution.
The pulsating signal may further be encoded using a predetermined resolution for the respective control parameter. The resolution used to encode the pulsating signal may be selected according to the type of control parameter, tolerances of the sensors, operating flow rate, operating rotation speed, or other relevant factors. This allows important control parameters to be encoded with a high resolution and less important control parameters to be encoded with a low resolution. If a fast transmission time is desired, then the resolution may be reduced.
The resolution may optionally be determined as the ratio between the range of the control parameter and the maximum second pulse length.
The control parameter, i.e. the first and second control parameter, may in example, but not limited to, be an inclination angle relative to a vertical direction, a compass direction (or azimuth angle) relative to magnetic north, a pressure or a flow rate of the drilling fluid, a rotational speed or a rotational torque of the drill string, vibrations in drill string, or other relevant control parameters relating to the operation. The control parameter may also, but not limited to, be a gamma count, a downhole temperature, rock formation density, porosity or resistivity, or other relevant control parameters relating to the characteristics of the rock formation. This allows the downhole tool to be adapted for different applications and for different measurements.
In example, the inclination angle may be measured between 0 degrees and 90 degrees and/or the compass direction may be measured between 0 degrees and 359 degrees. This inclination angle and/or compass direction may be encoded using a resolution of one, i.e. 1 degree corresponds to 1 second. Alternatively, the inclination angle and/or compass direction may be encoded using a resolution of greater than one, e.g. 4 degrees or 2 degrees corresponds to 1 second, or smaller than one, e.g. 0.25 degrees or 0.5 degrees corresponds to 1 second.
According to one embodiment, the step of generating at least one pulsating signal comprises generating a positive or negative pulsating signal relative to a reference amplitude.
The pulsating signals may be generated as mud pulses in a drilling fluid circulated in the borehole. The mud pulse may be generated as a positive or negative pulse by temporary opening and closing a valve element or sleeve inside the downhole tool. The movement of the valve element or sleeve may be controlled by a control unit inside the downhole tool. This causes a temporary increase or decrease in the pressure of the drilling fluid which can be detected at ground level by a simple receiver or a pressure transducer/gauge. This is particularly suited for deep boreholes and most rock formations.
Alternatively, the pulsating signals may be generated and transmitted to ground level using an electrical wired connection or another wireless connection. This is suited for shallow boreholes and underbalanced drilling applications.
According to one embodiment, the method further comprises the steps of: measuring at least a second control parameter, generating at least a second pulsating signal via the at least one downhole tool, the second pulsating signal comprising a value of the second control parameter, transmitting the second pulsating signal to the ground level.
The present method allows for measurement of more than one control parameter via the downhole tool. Different sensor units may be used to measure different types of control parameters. This increases the functionality of the downhole tool.
In example, but not limited to, the first control parameter may be the inclination angle while the second control parameter may be the compass direction or another relevant control parameter. These measurements may be combination with other measurements which are also transmitted to ground level via pulsating signals.
According to one embodiment, the method further comprises the steps of:
prior to operating the drill string, performing a test of the at least one downhole tool by:
pumping a drilling fluid into the drill string via a pump system, monitoring the pressure of the drilling fluid within a predetermined time window, stopping the pump system, measuring at least one of the first control parameter and the second control parameter, and optionally, restarting the pump system so that pumping of the drilling fluid is resumed.
The present method allows for a quick and easy installation of the downhole tool as no specialised engineers or technicians are required. The downhole tool can thus be unpacked and directly mounted in the drill string, thereby significantly reducing the installation costs and time.
The present method further allows for a quick and simple surface test prior to operating the drill string. The pump system may initially be started so that drilling fluid is pumped through the downhole tool. The pumping is continued for a predetermined time period, e.g. between 1 minute and 5 minutes. The pressure of the drilling fluid may be kept stable at a predetermined pressure level or above a minimum pressure threshold, e.g. between 10 bar and 100 bar.
The control unit may at the same time monitor the pressure of the drilling fluid within this predetermined time period. The control unit may then be activated as described later.
The pumping may then be stopped and a measurement of the respective control parameters may be performed by the downhole tool. The pumping may finally be restarted after a short time period.
One or more pulsating signals may then be generated based on the measured values of the control parameters. The pulsating signals may be transmitted to ground level directly after the measurements are done. Alternatively, the pulsating signals may be transmitted when the control unit detects that the pumping is restarted or after a predetermined event.
No additional calibration or setup process is required to perform the surface test, nor does the surface test require the use of an advanced user interface.
According to one embodiment, the method further comprises the step of activating the at least one downhole tool when a predetermined event is detected, e.g. a predetermined pressure of a drilling fluid.
The downhole tool may be operated in a sleep mode when no measurements and/or transmission of data are required. During the sleep mode, only an activation unit may be powered in order to detect the predetermined event, all other units of the downhole tool may be deactivated or powered off. This saves power and eliminates the need for an on/off button on the housing of the downhole tool.
The activation unit may in the sleep mode monitor the pressure of the circulating drilling fluid, e.g. the differential pressure between the drilling fluid in a central fluid conduit and the returning drilling fluid in the annulus. The measured pressure, e.g. differential pressure, may be compared to the minimum pressure threshold or a predetermined pressure value. If the measured pressure remains above the minimum pressure threshold or remains stable relative to the predetermined pressure value within the predetermined time period, then rest of the downhole tool is activated or powered on and operated in an operation mode. The pressure may then be raised by the desired operating level. This allows for a fast and accurate activation of the downhole tool.
The downhole tool may in the operation mode further monitor the pressure of the circulating drilling fluid, e.g. the differential pressure, in order to detect when pumping is stopped. Once the control unit detects that the pumping has stopped, e.g. dropped below the minimum pressure threshold, then the control unit may initiate the measurement of the respective control parameters and/or storage thereof. Alternatively, the downhole tool may remain in the sleep mode and only be activated when the activation unit further detects that the pumping has stopped.
The rotation of the drill string may alternatively or additionally be monitored and used to activate the downhole tool and/or trigger the measurements of the control parameters or transmission of the data.
An object of the invention is also achieved by a system for monitoring one or more control parameters in a borehole, comprising:
a drill string with at least one downhole tool, e.g. a drift indicator tool or a measurement while drilling tool, configured to be positioned in the borehole, an operating system located at a ground level, wherein the operating system is configured to operate the drill string in the borehole, the at least one downhole tool comprises at least a first sensor unit configured to measure at least a first control parameter and a control unit configured to detect an event, the at least one downhole tool further comprises a pulse generating unit configured to generate at least one pulsating signal and to transmit said at least one pulsating signal to the ground level, wherein the at least one pulsating signal comprises a value of the first control parameter, wherein the at least one pulsating signal comprises a single pulse having a predetermined pulse amplitude, wherein the pulse generating unit is further configured determined to determine the pulse length as function of the value of the first control parameter.
This provides a cheap and simple system for surveying directional movement of a drill string in a borehole without the use of a surface decoder system. No specialised engineers or technicians are required to install and operate the system. The system can be operated by simply monitoring the pressure of the drilling fluid at ground level, thus no advantaged user interface is required. The rig personnel can thus perform other tasks while the survey is transmitted. This significantly reduces the installation and operation costs.
The present downhole tool can simply be unpackaged and mounted in the drill string, wherein a quick and simple test of the downhole tool can be performed before continuing with the operation of the drill string. No nozzles are needed to operate the downhole and no calibration or setup procedures are required when installing the downhole tool.
The downhole tool may suitably be configured as a drift indicator tool or a measurement while drilling tool. The downhole tool may be located at any positions behind the drill bit, preferably just behind or near the drill bit for optimal measurements. The downhole tool comprises a pulse generating unit configured to encode the measurements into one or more pulsating signals by determining the pulse length as function of the measured value of the control parameter. The pulsating signals may be transmitted to ground level via a drilling fluid. Alternatively, other wired or wireless connections may be used.
According to one embodiment, the at least one downhole tool further comprises at least a second sensor unit configured to measure at least a second control parameter, wherein the at least one downhole tool is further configured to generate at least a second pulsating signal and to transmit said second pulsating signal to the ground level, wherein the second pulsating signal comprises a value of the second control parameter, π
The downhole tool may comprise at least two sensor units configured to measure different types of control parameters as described above. The sensor units may be connected to a control unit and an optional memory unit for storing the measurements. The control unit is further connected to the pulse generating unit for transmission of the pulsating signals. The sensor unit may in example, but not limited to, be a magnetometer, a gyroscope, a gamma sensor, an accelerometer, a pressure sensor, a temperature sensor, a vibration sensor, a logging device for measuring characteristics of the rock formation, or other relevant sensor units. The logging device may comprise a transmitter (e.g. a radioactive or piezoelectric source) and a receiver (e.g. multiple detectors).
The pulsating signal received at ground level may simply be detected by monitoring the pump pressure of the drilling fluid. The rig personnel just have read the pulse length of the pulsating signal which can be transformed into a representative value for the control parameter. This may be done using a simple look-up table. No complex decoding algorithms or user interfaces are required to read the survey.
According to one embodiment, the at least one downhole tool further comprises an activation unit configured to activate the downhole tool when a predetermined event is detected.
The downhole tool may be powered by a local power unit, e.g. a battery, a progressive cavity pump, or a combination thereof. The local power unit may be used to power the various electrical components in the downhole tool. The capacity of the battery may be selected so that it is able to power the downhole tool for at least 1000 operating hours or at least 1000 pulse cycles, preferably at least 1500 pulse cycles.
An activation unit may be used to reduce energy consumption in the downhole tool. The activation unit may comprise one pressure sensor configured to measure an internal pressure or external pressure of the drilling fluid. Two pressure sensors may be used to measure a differential pressure of the drilling fluid. The activation unit may be configured to monitor the pressure, e.g. the differential pressure, and to determine if the pressure remains above the minimum pressure threshold or remains stable relative to the predetermined pressure value within the predetermined time period as described above. No on/off buttons are thus needed to activate the downhole tool. This allows the downhole tool to be activated without rotation of the drill string.
Alternatively, the activation unit may be configured to further monitor the rotation of the drill string and activate the downhole if both the pump system and the rotation system are activated. This allows the downhole tool to be activated when rotation of the drill string is also present.
According to one embodiment, the control unit is further configured to detect said event by monitoring an operating parameter, e.g. pumping status, of the operating system within a predetermined time window.
The activation unit may be configured to monitor an operating parameter, e.g. the pumping status and/or the rotation status, using the sensor units. The pumping status may be detected by monitoring the pressure of the drilling fluid. If the pressure exceeds the pressure threshold or is kept stable at predetermined pressure level, this may indicate that the pump system is started. The rotation status may be detected as rotational movement of the drill string, e.g. as an increase in torque or vibrations, this may indicate that the rotation system is activated.
The control unit may be configured to further monitor the operating parameter in the operation mode or during the test in order to detect a first event. If the pressure drops below the pressure threshold or below the predetermined pressure level, this may indicate that the pump system is stopped. If the rotational movement of the drill string is stopped, e.g. a decrease in torque or vibrations, this may indicate that the rotation system is stopped. This indicates that the survey, i.e. measurements of the control parameters, should be taken.
The control unit is configured to initiate the measurement of the control parameters and/or store the measurements in a memory unit when the first event is detected, e.g. the pumping and/or rotation stopped. Once the measurements are completed, then the downhole tool may return to the sleep mode or continue to monitor the operating paDK 179179 B1 rameter in order to detect a second event, e.g. the pumping and/or rotation is restarted. This indicates that the survey can be transmitted to ground level.
The control unit may be configured to send a control signal to the pulse generating unit, after the second event is detected, which then generates the pulsation signal as described above. Alternatively, the activation unit may be configured to detect the second event and then activate the downhole tool which, in turn, activates the pulse generating unit. Once generated, the pulsating signal is transmitted to ground level.
According to one embodiment, the at least one downhole tool further comprises at least one memory unit configured to store measurements of at least one of the first control parameter and the second control parameter.
Instead of transmitting the pulsating signals to ground level after each second event, the measurements may be stored in the memory unit within the downhole tool. The measurements may then be downloaded onto an external device upon retrieval of the downhole tool. This further reduces the power consumption and, thus, increases the operating time of the downhole tool.
Alternatively, the measurements may be temporarily stored in the memory unit until the control unit, or activation unit, detect the second event. The measurements may then be encoded as described above and transmitted to ground level.
The invention is not limited to the embodiments described herein, and thus the described embodiments can be combined in any manner without deviating from the objections of the invention.
Description of the Drawing
The invention is described by example only and with reference to the drawings, wherein:
Fig. 1 shows a system comprising an operating system and a drill string with a downhole tool according to the invention,
Fig. 2 shows an exemplary embodiment of the downhole tool,
Fig. 3 shows a method of operating the downhole tool when operating the drill string,
Fig. 4 shows a method of performing a test of the downhole tool,
Fig. 5 shows a graph of the monitored pressure at ground level comprising an exemplary pulsating signal, and
Fig. 6 shows a graph of the monitored pressure at ground level comprising two exemplary pulsating signals.
In the following text, the figures will be described one by one, and the different parts and positions seen in the figures will be numbered with the same numbers in the different figures. Not all parts and positions indicated in a specific figure will necessarily be discussed together with that figure.
Position number list
1. Operating system
2. Drill string
3. Pump system
4. Drilling fluid
5. Rotation system
6. Borehole
7. Drill bit
8. Downhole tool
9. Gauge
10. Control unit
11. Power unit
12. Activation unit
13. First sensor
14. Second sensor
15. Memory unit
16. Pulse generating unit
17. Operate drill string
18. Stop pumping
19. Measure control parameter
20. Restart pumping
21. Transmit pulsating signal
22. Start pumping
23. Monitor pressure
24. Pulsating signal, first pulsating signal
25. Second pulsating signal
Detailed Description of the Invention
Fig. 1 shows a system according to the invention, comprising an operating system 1 connected to a drill string 2, wherein the operation of the drill string 2 is controlled by the operating system 1. The operating system 1 is located at ground level and comprises a pump system 3 configured to pump a drilling fluid 4 through the drill string 2 and back to ground level via the annulus. The operating system 1 further comprises a rotation system 5 configured to rotate the drill string 2.
The drill string 2 is positioned in a borehole 6 and comprises a drill bit 7, a downhole tool 8 and one or more intermediate drill string parts. The downhole tool 8 is configured to measure one or more control parameters in the borehole 6 and transmit these measurements to ground level via the drilling fluid 4. The downhole tool 8 can be installed and operated without specialised engineers or technicians, which significantly reduces the installation and operation costs.
The operating system 1, e.g. the pump system 3, comprises a gauge 9 or other means of reading the pump pressure. This enables the rig personnel to simply monitor the pump pressure in order to read the survey, no advantaged user interface or surface decoder system is required.
Fig. 2 shows an exemplary embodiment of the downhole tool 8 comprising a control unit 10, e.g. a microprocessor or logic circuit, configured to control the operation of the downhole tool 8.
A power unit 11 arranged in the downhole tool 8, or alternatively connected to the downhole tool 8, is used to power the various electrical components in the downhole tool 8. An activation unit 12 is further connected to the control unit 10 and configured to monitor an operating parameter, e.g. pressure of the drilling fluid, in order to detect a first event. When the first event is not present, then the downhole tool 8 is operated in a sleep mode where power to the other units in the downhole tool 8 is switched off. When the first event is present, then power to the other units in the downhole tool 8 is switched on and the downhole tool 8 is operated in an operation mode.
The downhole tool 8 comprises one or more sensor units configured to measure different control parameters. A first sensor unit 13 is used to measure an inclination angle relative to a vertical direction. A second sensor unit 14 is used to measure an azimuth angle perpendicular to the vertical direction. Other sensor units (marked by dotted lines) may also be arranged in the downhole tool 8.
The measured values for each control parameter (e.g. inclination angle and azimuth angle) can be stored in an optional memory unit 15 before being transmitted to ground level or downloaded into an external device.
The control unit 10 is further connected to a pulse generating unit 16 configured to generate and transmit one or more pulsating signals (see figs. 5 and 6) via the drilling fluid. The outputs of the sensor units 13, 14, or stored measurements thereof, is used as input for the pulse generating unit 16. According to the invention, each pulsating signal comprises a single pulse, wherein the pulse length is determined as function of the value of the control parameter (see fig. 5). No complex pulse transmission systems or frequency and/or amplitude modulation is required to encode the pulsating signal as only the pulse length is varied.
Fig. 3 shows a method of operating the downhole tool 8 during operation of the drill string 2.
Initially, the drill string 2 is operated 17 via the operating system 1 to perform a drilling procedure. The pump and rotation systems 3, 5 are started and the drill bit 7 is moved forward and loose particles or rocks are removed via the drilling fluid 4.
The downhole tool 8 is operated in the operation mode, and the control unit 10 monitors the pressure of the drilling fluid.
The pump system 3 and thus the pumping are stopped 18, which is then detected by the control unit 10 as a decrease in the monitored pressure.
The downhole tool 8 then perform a measurement 19 of the respective control parameters. The measurements are temporary stored in the memory unit 15.
The pump system 3 and, thus, the pumping are restarted 20 which is then detected by the control unit 10.
The measured value of the respective control parameters are transmitted to the pulse generating unit 16 which determines a corresponding pulse length of the pulsating signal. The pulsating signal is thus generated and transmitted 21 to ground level. The pulse length of the pulsating signal can thus be read via the gauge 9 and transformed into a representative signal of the control parameter.
Fig. 4 shows a method of performing a test of the downhole tool 8 before starting the operation of the drill string 2.
Once mounted in the drill string 2, at least the pump system 3 of the operating system 1 is started 22.
The activation unit 12 then monitors 23 the differential pressure of the drilling fluid 4 within a predetermined time window via two pressure sensors located in the downhole tool 8. The activation unit 16 activates the downhole tool 8 when the first event is detected, e.g. the differential pressure is increased to a predetermined pressure value and kept stable relative to that pressure level.
The pumping is afterwards stopped 18, and the downhole tool 8 performs a measurement of the respective control parameters. The pumping is then restarted 20 via the pump system 3.
The measured values of the control parameters are then transmitted to the pulse generating unit 16 which, in turn, generates a pulsating signal as described above. This pulsating signal is then transmitted 21 to ground level where the rig personnel can read the survey, i.e. the pulsating signal, to confirm that the downhole tool 8 is functioning properly.
Fig. 5 shows a graph of the monitored pressure at ground level comprising an exemplary pulsating signal 24. The pulsating signal 24 has a single pulse with a predetermined amplitude and a pulse length determined as function of the value of the control parameter. The pulsating signal 24 is generated as a positive pulse (see figs. 5 and 6) or a negative pulse (see fig. 6) relative to a normal pressure level, Po, used to operate the drill string 2.
The single pulse comprises a first or constant pulse section and a second or variable pulse section. The pulse length, tb of the first pulse section corresponds to a minimum value of a measured control parameter. Here, the first pulse section has a pulse length, ti, of 5 seconds. Thus, if a minimum value of the control parameter is measured, then the pulse length of the pulsating signal 24 corresponds to the pulse length, tp
The pulse length, t2, of the second pulse section is determined as function of the measured value of the control parameter. The pulse length, t2, may thus vary between the minimum value and a maximum value. Here, a value of 12 degrees is measured for the control parameter, then the pulse length of the pulsating signal 24 corresponds to the sum of the pulse length, ti, and the pulse length, t2, i.e. 17 seconds.
A resolution of 1 degree per 1 second is used to generate the pulsating signal 24.
Fig. 6 shows a graph of the monitored pressure at ground level comprising two exemplary pulsating signals. Here, the first pulsating signal 24 is generated as a positive pulse while a second pulsating signal 25 is generated as a negative pulse. Alternatively, both pulsating signals 24, 25 may be generated as a positive or negative pulse.
A first control parameter, e.g. inclination angle, is encoded into the first pulsating sig5 nal 24, while a second control parameter, e.g. azimuth angle, is encoded into the second pulsating signal 25.
Here, the first pulsating signal 24 has a pulse length, t3, of 11 seconds corresponding to a measured inclination angle of 6 degrees. The second pulsating signal 25 has a pulse length, U, of 9 seconds corresponding to a measured azimuth angle of 4 degrees. The first pulse section has the same pulse length, tb as described in relation to fig. 5.
Claims (2)
Priority Applications (4)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| DKPA201670742A DK179179B1 (en) | 2016-09-21 | 2016-09-21 | System and method for transmission of pulses |
| PCT/DK2017/050273 WO2018054436A1 (en) | 2016-09-21 | 2017-08-25 | System and method for transmission of pulses |
| EP17761182.9A EP3516168A1 (en) | 2016-09-21 | 2017-08-25 | System and method for transmission of pulses |
| US16/334,928 US20190284932A1 (en) | 2016-09-21 | 2017-08-25 | System and method for transmission of pulses |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| DKPA201670742A DK179179B1 (en) | 2016-09-21 | 2016-09-21 | System and method for transmission of pulses |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| DK179179B1 true DK179179B1 (en) | 2018-01-15 |
| DK201670742A1 DK201670742A1 (en) | 2018-01-15 |
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Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| DKPA201670742A DK179179B1 (en) | 2016-09-21 | 2016-09-21 | System and method for transmission of pulses |
Country Status (4)
| Country | Link |
|---|---|
| US (1) | US20190284932A1 (en) |
| EP (1) | EP3516168A1 (en) |
| DK (1) | DK179179B1 (en) |
| WO (1) | WO2018054436A1 (en) |
Families Citing this family (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN109356570B (en) * | 2018-11-22 | 2022-06-17 | 长江大学 | Method and equipment for transmitting drilling guide parameters |
| CN112543027B (en) * | 2020-12-16 | 2022-11-15 | 中国石油大学(华东) | Narrow pulse width negative pulse type downlink signal decoding method and system based on pattern recognition |
Citations (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US4866680A (en) * | 1977-12-05 | 1989-09-12 | Scherbatskoy Serge Alexander | Method and apparatus for transmitting information in a borehole employing signal discrimination |
| US20080068210A1 (en) * | 2006-09-18 | 2008-03-20 | Schlumberger Technology Corporation | Downlink based on pump noise |
| US20090120689A1 (en) * | 2007-11-12 | 2009-05-14 | Baker Hughes Incorporated | Apparatus and method for communicating information between a wellbore and surface |
Family Cites Families (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| NO851439L (en) | 1984-04-12 | 1985-10-14 | Dies Downhole Drilling Inc | EQUIPMENT FOR MEASURING SLIM PULSE. |
| WO2012094242A2 (en) * | 2011-01-04 | 2012-07-12 | Welltronics Applications LLC | Method for a pressure release encoding system for communicating downhole information through a wellbore to a surface location |
-
2016
- 2016-09-21 DK DKPA201670742A patent/DK179179B1/en not_active IP Right Cessation
-
2017
- 2017-08-25 WO PCT/DK2017/050273 patent/WO2018054436A1/en active Search and Examination
- 2017-08-25 EP EP17761182.9A patent/EP3516168A1/en not_active Withdrawn
- 2017-08-25 US US16/334,928 patent/US20190284932A1/en not_active Abandoned
Patent Citations (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US4866680A (en) * | 1977-12-05 | 1989-09-12 | Scherbatskoy Serge Alexander | Method and apparatus for transmitting information in a borehole employing signal discrimination |
| US20080068210A1 (en) * | 2006-09-18 | 2008-03-20 | Schlumberger Technology Corporation | Downlink based on pump noise |
| US20090120689A1 (en) * | 2007-11-12 | 2009-05-14 | Baker Hughes Incorporated | Apparatus and method for communicating information between a wellbore and surface |
Also Published As
| Publication number | Publication date |
|---|---|
| WO2018054436A1 (en) | 2018-03-29 |
| DK201670742A1 (en) | 2018-01-15 |
| EP3516168A1 (en) | 2019-07-31 |
| US20190284932A1 (en) | 2019-09-19 |
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Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| PBP | Patent lapsed |
Effective date: 20200921 |