|Publication number||USRE42426 E1|
|Application number||US 11/657,746|
|Publication date||Jun 7, 2011|
|Filing date||Apr 27, 2000|
|Priority date||Apr 27, 1999|
|Also published as||CA2407347A1, CA2407347C, DE60018402D1, DE60018402T2, EP1177366A1, EP1177366B1, US6847304, WO2000065198A1|
|Publication number||11657746, 657746, PCT/2000/1629, PCT/GB/0/001629, PCT/GB/0/01629, PCT/GB/2000/001629, PCT/GB/2000/01629, PCT/GB0/001629, PCT/GB0/01629, PCT/GB0001629, PCT/GB001629, PCT/GB2000/001629, PCT/GB2000/01629, PCT/GB2000001629, PCT/GB200001629, US RE42426 E1, US RE42426E1, US-E1-RE42426, USRE42426 E1, USRE42426E1|
|Inventors||Stephen John McLoughlin|
|Original Assignee||Halliburton Energy Services, Inc.|
|Export Citation||BiBTeX, EndNote, RefMan|
|Patent Citations (8), Referenced by (1), Classifications (8), Legal Events (6)|
|External Links: USPTO, USPTO Assignment, Espacenet|
This application claims the benefit of provisional 60/131,208 filed on Apr. 27, 1999.
The present invention is concerned with the field of downhole tools. More specifically, the present invention is concerned with an apparatus and method for transmitting information to a downhole tool.
A drilling tool or member is a device suitable for drilling a well bore or the like. As the drilling tool drills further into the ground, communicating with the tool becomes more and more difficult. Other downhole tools, variously referred to as “production tools”, fulfilling different functions from drilling tools yet having similar data requirements to drilling tools are considered equally within the scope of this apparatus and method.
The recognised team in the art for the method of transmitting information from the drilling tool to the surface is ‘telemetry’. Telemetry can be achieved by many meats, for example, ‘hardwire’, where the signal is passed along a conducting medium via electrical means and to which the drilling tool is attached.
The above telemetry method requires the provision of a separate communication route for the electrical signal from the surface. This provides drawbacks in terms of both cost and potential reliability as the signal must reach the tool when the tool is many miles below the surface.
A telemetry medium for communicating with the tool should ideally be one of the parameters which is readily available in either drilling or production scenarios. A drilling parameter is a parameter which must be supplied to the drilling tool in the vast majority of drilling scenarios.
Drilling parameters such as the ‘weight-on-bit’, pump cycling and drill string rotation have been previously been considered. However, generally, these have been used just to toggle a switch between two states and represent, at worst a binary switching device and, at best a means of stepping through multiple options.
The drill string rotation is a drilling parameter which is common to almost all rotary drilling operations. This is typically mea ed in revolutions per minute (RPM). Variations in the rotation of the drill string can be used, be that in terms of the actual rotational velocity, the time when the drilling sting is continuously rotating at a continuous speed or a measured time when the drill string is not rotating can be used to transmit a sophisticated command sequence, wherein the rotary command parameter has magnitude. This is as opposed to the conventional toggle signal transmitted down the drill string to the drilling tool. Thus, this new apparatus and method addresses all the problems posed by known prior art.
Although the term “drill string” has been used, it will be appreciated that the “drill string” could be any tubular which is connected to a downhole tool. For example, rotation of a production string could also be used if the downhole tool is a production tool. A tubular can be any pipe or any medium which generally connects the downhole tool (when in position in the well bore) with a surface control station, providing that rotation of the tubular at the surface causes rotation of at least a part of the tubular at the downhole tool.
Therefore, in a first aspect, the present invention provides an apparatus for use in drilling or producing from a well bore, the apparatus comprising a downhole member capable of being attached to a tubular, means for rotating a tubular, control means for controlling the rotation of said tubular in order to transmit information along said tubular and means for monitoring the rotation of said tubular and for decoding said information transmitted along said tubular such that a magnitude of a parameter can be determined from the rotation of said tubular.
As previously described, the tubular may be a drill string, production string or the like. The downhole member may be a drilling tool, production tool or the like.
In a second aspect, the present invention provides a method for transmitting information along a tubular to a downhole member located within a well bore, the method comprising the steps of:
The variation in the tubular rotation may be provided by varying the rotational velocity or frequency of the tubular, measuring the time for continuous rotation of the tubular, measuring the time between successive rotations of the tubular (i.e. the time when the tubular is not rotating), or any of the above parameters in either separately or in combination etc.
This ability to vary the rotational speed or frequency of the tubular allows a magnitude to be communicated to the downhole member as opposed to just a binary signal. Therefore a signal, such as a magnitude of the change in a drilling angle can be communicated to the tool by using just the tubular rotation. Explicitly, the measured frequency of the tubular at the downhole member can communicate a numerical value to the drill string.
The rotation or frequency of the tubular may be monitored by the use of an emitter device which emits a signal or influences its environment such that the rotation of the drill string is used to activate a sensor means.
The emitter device which emits a signal or influences its environment may comprise a magnet. Alternatively, or in addition to the magnet, the device may also comprise a device which emits a sonic or a radioactive signal.
The emitter device may be located on the tubular or rotating part of the apparatus connected to the tubular or on a non-rotating pant of the apparatus.
The emitter device may comprise a mechanical switch which is activated by the rotation of the tubular, such that each revolution is equal to an analogue or digital data point.
The rotation of the tubular may be monitored using a sensor. The sensor may sense a field or a change in a field or signal emitted by the emitted. For example, if the emitter is a magnet then the sensor may be a Hall effect device or a magnetometer. Alternatively, the sensor may by used to sense changes in an inherently present parameter due to the rotation of the tubular. For example, the sensor may comprise an accelerometer which receives direct alternating gravitational data inputs as a direct result of the rotation of the tubular. Such a sensor would preferably sense the centre of the Earth for use in controlling a Measurement-While-Drilling, Logging-While-Drilling or similar device. The sensor regardless of its type, may be activated by the rotating tubular such that each resolution of the drill string is equal to an analogue or binary data point. The sensor may be located on the tubular, a rotating part of the app us connected to the tubular or a non rotating part of the apparatus or a non-rotating part of the apparatus depending on the location of th emitter.
Preferably, the sensor means comprises a timing device such that sensor outputs derived from the rotation of the tubular may be measured over time.
A plurality of emitters and/or sensors may be provided. If a plurality of emitter devices and/or sensor means are provided then each of the devices and/or sensor means may be actuated in an independent or sequential manner. The plurality of emitters may be located radially or axially on the rotating drill string. If the emitters are a plurality of magnets then the magnets may be aligned with alternating polarities.
The output from the sensor means may be analogue or digital. The output from the sensor means will generally be provided to a drive means or a logic means in order to control the drilling member or other device in accordance with the information transmitted down the drill string.
The sensor is preferably isolated from wellbore fluids and may be contained in a pressure housing. More preferably, the pressure housing is magnetically transparent. The output from the sensor may be utilized for triggering an activation means in the instrumentation of the downhole member or an assembly which is housed in a separate physical housing. The activation means may be logical, electronic, mechanical or physical in form. The activation means may be capable of activating multiple devices in either an independent or sequential manner. The activation means may be bi-phase, incremental or continuous in nature.
The above apparatus or method preferably uses phase shift modulation or other means of checking for errors or variances in the tubular rotation.
The apparatus and method according to the first and second aspects of the invention (respectively) may be used with any downhole device where it is necessary to transmit a control parameter to the device, for example, to control the drilling direction.
However, they are especially suited for use with a wellbore directional steering tool as described in WO-A-96/31679. The latter device is an apparatus for selectively controlling from the surface, the drilling direction of wellbore. It comprises a hollow rotatable mandrel, an inner sleeve, an outer housing, a plurality of stabilizer shoes and a drive means. The hollow rotatable mandrel has a concentric longitudinal bore. The inner sleeve is rotatably coupled about the mandrel and has an eccentric longitudinal bore of sufficient diameter to allow free relative motion between the mandrel and the inner sleeve. The outer housing is rotatably coupled around the inner eccentric sleeve and has an eccentric longitudinal bore forming a weighted side. The outer housing also has sufficient diameter to allow free relative motion between the inner sleeve. Two stabilizer shoes are longitudinally attached to or formed integrally with the outer surface of the outer housing. Finally, the drive means is arranged for selectively rotating the inner eccentric sleeve with respect to the outer housing.
An embodiment of the directional tool is shown in
The inner rotating mandrel 111, is attached directly to a drill bit 107. However, the threads may differ between the two elements and an adapter sub may be required for matching purposes.
FIGURE B shows the relative eccentricity of the inner, 112 and outer, 113 eccentric sleeves (outer housing). The outer housing consists of a bore passing longitudinally through the outer sleeve which accepts the inner sleeve. The outer housing is eccentric on its outside, shown as the “pregnant portion”, 120.
The pregnant portion or weighted side, 120 of the outer housing forms the heavy side of the outer housing and is manufactured as a part of the outer sleeve. The pregnant housing contains the drive means for controllably turning the inner eccentric sleeve within the outer housing. Additionally, the pregnant housing may contain logic circuits, power supplies, hydraulic devices, and the like which are (or may be) associated with the ‘on demand’ turning of the inner sleeve.
There are two stabilizer shoes, 121, on either side of the outer housing located at right angles to the pregnant housing and on the centre line drawn through the center of rotation on the inner sleeve. These two shoes serve to counter any reactionary rotation on the pan of the outer housing caused by bearing friction between the rotating mandrel 111 and the inner eccentric sleeve 112. The stabilizer shoes are normally removable and are sized to meet the wellbore diameter. The same techniques used to size a standard stabilizer can be applied in choosing the size of the stabilizer shoes. Alternatively, the shoes 121 can be formed integrally with the outer housing 113. The pregnant or weighted portion of the outer housing 113, will tend to seek the low-side of the hole and the operation of the apparatus depends On the pregnant housing being at the low-side of the hole.
The manner of functioning of the apparatus and method of the present invention to control a drilling device such as a directional drilling device as shown in Figures A and B will be described in more detail hereinbelow.
The present invention will now be described with reference to the following non-limiting preferred embodiments in which;
Surface station 23 is provided with rotation control means 27 which controls the rotation of the drill string. The drilling tool 21 has monitoring means 29 which monitors the rotation of the drill string 25.
The output of the accelerometer in
The first rotation cycle has a period of t1. Once this cycle is completed, the speed of rotation of the drill string is reduced over the second cycle until a third cycle with a period of rotation t2 is achieved. Period t2 is longer than period t1, therefore, the speed of rotation in the first cycle is greater than that of the third cycle. Thus, a change in the rotation speed of the drill string can be detected at the drilling member or drilling tool. Hence, the rotation frequency of the drill string can be used to instruct the drilling member, downhole device or tool.
After time period , the rotation of the drill string is either reduced to zero or is reduced below a threshold value for time period . The threshold value is R0. Time period  is primarily used to create a clear distinction between instructions.
The frequency of rotation of the drill string is then increased to R2 for time period . This variation in the rotation frequency represents an easily identifiable codification as it varies both in rotational frequency and duration from time period . The duration of time period  is restricted once again by reducing the rotational frequency to below threshold value R0 for a second time period . After the second time period  the rotation frequency is increased to R3 for time period . Rotational frequency R3 is lower than that of R1 and R2. Time period  can be used as a separate data set or it can be used as supplemental data set to that transmitted in im period . It may also be used as a preamble to a following data set (in a similar manner to the data set of period ) or it may be used as a terminating data set which may return the parameters of the tool to an equilibrium position.
There are thus two data variables in each data set i.e. frequency and duration, which may be controlled from the surface. To summarise, these two variables may be used in a number if different ways in order to talk to the tool. The tool may have a number of different parameters which require instructions from the surface. The parameter which is to be changed may be set by the measured velocity or frequency of rotation and the amount which the parameter is to be changed by may be set by the duration of the signal. Alternatively, the parameter may be chosen by a preparatory data sequence (e.g. period  and the magnitude of the parameter may be communicated by the magnitude of the following velocity or frequency signal.
Averaging, standard code correction techniques, or other statistical means may be employed to improve the quality of the data obtained from each individual data set. Any number of data sets may be sequentially added in order to increase the quantity of data transmitted to the downhole instrumentation or mechanism(s).
In period 2, the rotation of the drill string is stopped, the logic means of the drilling member vary a set parameter. For example, if the drilling direction of the drilling member is governed by the angular movement of a component of the drilling member (for example, 112 in
When the drill string rotation is restarted, at the start of period 3, the movement of the component is stopped.
The movement of the component arts again at the start of period 4. (i.e. when the drill string rotation stops). Period 4 is twice as long as period 2. Therefore the component moves through twice the angle in period 4 as period 2.
Hence the duration of the period of non-rotation is converted into the angle of rotation for component 112.
The tool comprises a outer housing 1 with an eccentric bore. An inner sleeve 2 is located within said bore such that the outer housing 1 is rotatably coupled about said inner sleeve 2. The inner sleeve 2 also has an eccentric bore which is configured to accommodate a rotating drill string member 3 such that said inner sleeve 2 can rotate relative to both said outer housing 1 and aid drill string member 3.
A magnet 4 is attached to said rotating member 3. The magnet is located in a pocket on said rotating member 3, the magnet may also be attached by some other means, for example, by adhesives. This specific embodiment uses the magnet as an emitter. However, it will be appreciated by those skilled in the art that the magnet could be replaced by any type of emitting sensor.
The outer housing 1 contains instrument barrels 6. The instrument barrels 6 are provided with sensing means. During drilling of the well bore 7, the heavy portion of the outer housing seeks the low side of the well bore and the position of the outer housing remains relatively fixed with respect to the well bore. The drill string 3 and magnet 4 rotate relative to the outer housing. Lines of flux 5 radiate from the magnet 4 in such a manner as to overcome the Earth's ambient field. The field should also be set high enough to compensate for the reduction in field strength over distance. The flux lines 5 extend radially beyond the instrument barrel 6 such that sensors within the instrument barrel 6 can detect the intensity of the emitted magnetic field. It should also be noted that the magnetic field strength should also be calculated giving due consideration to the differences in magnetic field strength of the Earth at extreme Northerly and Southerly latitudes.
When the magnet 4 is rotated such that it is closest to the sensors in the instrument barrel 6, then a maximum in the magnetic field is detected. When the magnet 4 is furthest form the instrument barrel 6, then a minimum in the magnetic field is detected. The filed detected by the sensors may be sinusoidal if is possible to sense the radiated magnetic field at all times when the member 3 is rotating. However, as it is only necessary to measure the frequency of rotation of the member, it is adequate if the sensor is just configured to detect a maxima in the field when the magnet is at its closest to the sensor. In other words, the sensor just needs to detect a series of pulses where each pulse is equivalent to one each rotation of the member 3.
Thresholds may also be set which negate the effect of the Earth's magnetic field and which serve as limit switches. These limit switches may be employed as a means of logic control within the sensor array or within a logic control sub assembly.
A second instrument barrel 6a is also shown. This may also contain magnetic sensors. The provisions of two magnetic sensors allows the direction of the rotation of the drill string to be accurately determined as well as its magnitude.
The sensor which isolated within the instrument barrel is preferably situated in a stainless steel, or another magnetically transparent pressure vessel such that the instrumentation is isolated from the borehole pressure. The instrumentation barrel may comprises a magnetometer, or Hall effect device or the like for detecting the magnetic field.
Inevitably, there will be material between the magnetic sensor in the instrument barrel 6 and the magnet 4 located on the rotating member. This intervening material should, as far as possible, be magnetically transparent. In other words, the magnetic field should pass through this material without becoming deflected or distorted. Materials which exhibit these properties include austenic stainless steels and other non-ferrous material.
More sophisticated coding is achievable with more than one emitter. Further, the inversion of one of the sensors can be used to provide error checking or other programming advantages to the present invention. Multiple magnets may also be used to increase the frequency of the signal from the rotating member 3 or for actuation of multiple sensors within a single data set time frame, for example, as a means of compressing data.
Multiple magnets may have the same polarity or they may have alternating alignment of polarity. In
Although not shown in either of
In both the generalised and preferred embodiments of the assembly, it should be understood the different signalling means may be employed, that different configurations my be used and that other modifications may be made without departing from the spirit and scope of the present invention as defined by the appended claims.
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|Citing Patent||Filing date||Publication date||Applicant||Title|
|US20120007747 *||Dec 16, 2009||Jan 12, 2012||Rayonex Schwingungstechnik GbmH||Method and system for transmitting data from a device to a receiving unit|
|U.S. Classification||340/854.3, 175/45, 367/82, 73/152.03|
|International Classification||E21B47/12, G01V3/00|
|Sep 10, 2012||REMI||Maintenance fee reminder mailed|
|Jan 27, 2013||REIN||Reinstatement after maintenance fee payment confirmed|
|Jan 27, 2013||LAPS||Lapse for failure to pay maintenance fees|
|May 14, 2013||SULP||Surcharge for late payment|
|May 14, 2013||FPAY||Fee payment|
Year of fee payment: 8
|Sep 16, 2013||PRDP||Patent reinstated due to the acceptance of a late maintenance fee|
Effective date: 20130916