Patent Grant
8393413
This application is a National Phase entry of PCT Application No. PCT/GB2005/002668 filed 6 Jul. 2005 which claims priority to British Application No. 0415453.0 filed 9 Jul. 2004, both of which are incorporated herein by reference.
Not applicable.
The present invention relates to a tool and method for the closed loop control of the trajectory of a steerable drilling tool during the drilling of a bore hole.
The extraction of oil and gas from reserves situated below the Earth's surface involves the drilling of bore holes from the surface to the reserves. Typically, a drilling tool with a drill bit attached to its lower end is used to drill such holes. The upper end of the drilling tool attached to a drill string or drill pipe, which is attached to a drive assembly at the surface. The drive assembly causes the drilling pipe to rotate which transmits the rotary motion to the drilling tool and the drill bit. As the drilling tool sinks deeper into the ground, extra sections of drill pipe are added to the drill string.
Furthermore, it is known to provide steerable drilling tools. There are various different types of steerable drilling tool and one example is described in detail below. However, steerable drilling tools typically are capable of bending in response to operator instructions so that the direction of the bore can be changed.
Documents GB 2 392 931A, U.S. Pat. No. 6,233,524B1, WO 01/29372A1 and EP 0 806 542A2 all disclose steerable drilling tools.
One example of steerable drilling tools are rotary steerable tools. Whilst a rotary steerable tool may vary in principle, it will generally comprise of a bias or steering unit which exerts a force, either internally on a flexible central shaft or externally on the borehole wall to affect a change in the steering geometry to the desired direction.
In one mechanisation, the drill pipe is connected to a drive unit located at the surface and transmits the rotary motion of the drive unit via the rotary steerable tool to the drill bit. The rotary steerable tool comprises a flexible central shaft which is connected at its top end via the necessary connections to the drill pipe. The bottom end of the flexible shaft is similarly connected to the drill bit. The flexible shaft is supported by two bearing systems, one at either end. The upper bearing is designed to prevent bending of the shaft above it and the lower bearing is typically of the angular contact type and thus allows movement of the shaft above and below it.
Between the two bearings, around the centre of the length of the flexible shaft, is a bend unit that deflects the shaft. Various mechanisms may be implemented to cause the flexible shaft to be deflected to the designated amplitude so as to cause the correct angular deflection of the shaft in the required direction. It will be apparent that the portion of the flexible shaft located below the angular contact bearing will move in the contra-direction to the portion of the flexible shaft located immediately above the bearing in the bend unit. Other rotary steerable designs exist which generate deflection by alternative methods, for example, eccentric pressure pad application.
Alternatively, the rotary steerable tool may be connected to a device known as a mud motor. Fluid, known as mud, is pumped down the drill string into the mud motor which is positioned between the drill string and the rotary steerable tool. An impeller within the mud motor is driven by the movement of the fluid . The impeller is in turn connected to the rotary steerable tool, and thus the drill bit can be rotated.
Rotary steerable tools typically incorporate a reference stabilised housing which is de-coupled, either actively or passively, from the drill string. For example, the outer housing may be restrained from rotating with respect the drill hole walls by a reference stabiliser located along the outer housing. The stabiliser may comprise a plurality of guides, and in particular may be three or four sets of sprung rollers or contact pads which may accommodate over-gauge hole sections. The outer stabilised housing may in fact rotate in the same sense as the drill bit, but at a very slow rate as the system progresses down the hole. The reference stabiliser is designed and operated to ensure that the ratio of drill bit to outer housing turn rate does not exceed a fixed limit.
It can therefore be appreciated that as the drill bit and rotary steerable tool progress along the drilled bore hole, the trajectory of the assembly, and hence that of the borehole, can be controlled. This control is typically actioned and supervised by a drilling operator at the surface or start location of the bore hole.
In addition to operator controlled drilling, it is known to provide automated guidance of drilling tools using closed loop control systems. In order to implement automated guidance of the drilling tool using closed loop control, continuous, accurate information concerning the direction or position of the drill bit is required. In the absence of such information, drilling operator intervention may be required in order to ensure that the drill bit follows the desired bore hole path. However, in the oil and gas industries, the drilling environment can be particularly inhospitable. The vibrations caused by the drilling tool make it difficult to obtain the continuous, accurate information required. Furthermore, these problems are made worse at greater depths. In view of these factors, closed loop control drilling systems are generally difficult to implement in the oil and gas industries.
Document US 2002/0005297 A1 discloses a closed loop control system for use in the drilling of horizontal underground utility lines. Such lines are typically, drilled in soft sub-surface earth and the drilling system is thus not exposed to the same inhospitable environment experienced in the drilling of oil and gas bore holes. In view of this, this document does not address the problems outlined above in relation to providing continuous and accurate results.
Document U.S. Pat. No. 6,233,524 B1 also discloses a closed loop control system. This document is mainly concerned with extending drill life and improving drilling efficiency by taking various measurements relating to operating conditions and operating the drilling tool accordingly. The document also discloses that the system may be implemented as a navigation device. Although the system is designed for use in oil and gas drilling, it does not address the problems associated with obtaining continuous and accurate results.
GB 2 392 931A also discloses a closed loop control system.
In addition to the above disclosures, several techniques for obtaining directional/positional information are known as described in the following.
Measurement While Drilling (MWD) survey tools are located above the rotary steerable tool in the Bottom Hole Assembly (BHA). BHA is the term used to refer to the components and instruments positioned at the bottom of the drill string. The BHA does not necessarily include the drilling tool itself and in the present application the term BHA is used to refer to the components and instruments placed between the drilling tool and the drill string.
Such MWD survey tools comprise magnetometers and inclinometers which provide the drilling operators respectively with azimuthal deviation data (from a reference, e.g. magnetic north) and inclination measurements relating to the portion of bore hole in which the MWD survey tool and the BHA are currently located. When taken together these measurements provide information concerning the trajectory of the bore hole. Typically, the distance of the MWD survey tool from the surface, i.e. the well bore path length, is derived from the length of drill pipe which has been inserted into the well bore behind the MWD survey tool. Thus, the drilling operators are provided with the attitude (azimuth direction and inclination) of the bore hole at a given bore hole length. This information can be used by the drilling operators to guide the rotary steerable drilling tool.
However, there are various problems with the accuracy and latent reaction time of such a set-up. Firstly, given that the rotary steerable tool can be more than 18 feet long, the conventional MWD survey tool is located a considerable distance from the drill bit. Thus, if the drill bit veers off the desired trajectory (for example owing to rock mechanics) the drilling operator remains unaware of this condition until the MWD survey tool reaches the point at, or beyond which the unplanned deviation occurred. At this time the drill bit has progressed considerably along the deflected trajectory. Only at this point is the drilling operator aware that corrective action may be necessary.
MWDs cannot be placed on or near rotary steerable tools as MWDs comprise magnetometers and rotary steerable tools are constructed using magnetically permeable materials. Furthermore, magnetic sensors generally are difficult to operate on or near rotary steerable tools. Rotary steerable tools can be made out of non-magnetic permeable materials, but this is very expensive and generally avoided. Furthermore, even if non-magnetic materials were used in the construction of the rotary steerable tool, the presence of large diameter steel rotating bodies can result in induced electromagnetic forces generating variable, unstable magnetic fields which preclude the use of magnetometers or result in spurious sensor data. Magnetic interference may also result from the control or line currents within the rotary steerable tool. In particular, the system control circuits may create unstable magnetic fields resulting in local disturbances.
Secondly, as MWD survey tools are typically located within the BHA at the lower end of the drill string, while drilling is in progress, the MWD survey tool is subjected to a high degree of vibration and rotary forces. This makes it difficult to obtain accurate continuous survey data while drilling is in progress. Thus, in typical well bore drilling set-ups, drilling is stopped from time to time in order that accurate surveys may be undertaken, normally at pipe connections (typically at 30 m intervals).
Thirdly, the drill string is typically made up of multiple segments of drill pipe with the BHA located at the lower end. The BHA also comprises tubular components of variable cross section, diameter and length. Both the drill string and BHA are limber in nature which enables the drill string to progress along the variable radius curves of the drilled bore hole.
The BHA is normally composed of larger diameter, thicker walled, components, and is less limber than the drill string. In most, but not all, drilling applications, the BHA is stabilised and is nominally held concentric to the central axis of the bore hole. The standard MWD direction tool is in turn centralised within the BHA, thus providing sensor attitude data which can be said to represent the local bore hole axis, but not necessarily that of the newly drilled hole some distance below or ahead of the MWD tool.
The inherent flexibility of the BHA, and specifically, its connection to the rotary steerable system, is a necessary design attribute enabling the steering system to operate quasi-independently of the reaction forces of the BHA above. Hence, the rotary steerable system can be used to deflect the path of the bore hole in any desired attitude and direction.
For the above reasons, MWD survey tools of the type described above are not ideal for use in closed loop control systems.
At Bit Inclination (ABI) sensors (accelerometers) which are located within the outer housing of the rotary steerable tool itself are also known. Such sensors are typically within a few feet of the drill bit and can thus detect relatively quickly any undesired changes in bore hole inclination at or immediately behind the drill bit trajectory and the bore hole axis. However, this sensor configuration does not provide actual azimuthal change. For example, if the drill bit veers from the desired azimuthal trajectory, but maintains the desired inclination, the operator would not be aware of this condition until the MWD survey tool data becomes available for the relevant section of hole. Additionally, the bore hole, at drill bit depth, would have strayed further from the intended trajectory.
For the above reasons, ABI sensors of the type described above are also not ideal for use in closed loop control systems.
Documents US 2002/0005297 A1, U.S. Pat. No. 6,233,524 B1 and GB 2 392 931A were mentioned above in relation to disclosures of closed loop control systems. However, as discussed above, non of these documents address the issues relating to obtaining continuous and accurate sensor readings during the drilling process.
In document US 2002/0005297 A1, the down-hole sensors are positioned in a drill tube which is positioned proximate and rearward of the drilling tool. Positioning the sensors in such a manner has the same draw backs as described above in relation to the MWD. Thus, no solution is provided to the problem of providing continuous and accurate results.
In documents GB 2 392 931A and U.S. Pat. No. 6,233,524 B1, there is no disclosure relating to the problems associated with providing continuous and accurate results, and thus there is no disclosure relating to the positioning of the sensors in order to overcome these problems.
Documents WO 01/29372A1 and EP 0 806 542 A2 both relate to steerable drilling tools, however neither document discloses closed loop control of the direction or position of the drilling tool on the basis of sensors measuring the direction or position of the drilling tool. Neither document highlights the problems associated with the need to provide continuous and accurate results.
Thus, the above described prior art does not disclose any solutions to the problem of providing continuous and accurate sensor measurements for use in automated guidance of a drilling tool using closed loop control. The lack of continuous, accurate information concerning the direction of the drill bit, or reference quality positional information, means that drilling operator intervention is required in order to maintain the drill bit trajectory along the pre-planned well path in such systems.
The present invention provides a steerable bore hole drilling tool comprising: a tool body having a first end connectable to a drive means and a second end connectable to a drill bit, the tool body arranged to transmit rotary motion from said first end to said second end and comprising deflection means 70 arranged to deflect said second end away from a longitudinal axis of the tool body; a sensor unit; estimation means arranged to estimate the direction and/or position of the tool body on the basis of the output of said sensor unit; control means for calculating the difference between the estimated direction and/or position and corresponding pre-stored direction and/or position information and for controlling said deflection means so as to deflect said second end on the basis of said difference; and decoupling means arranged to mechanically decouple said sensor unit from the tool body.
By mechanically decoupling the sensor unit from the drilling tool, in use, the motion and vibrations generated by the drilling tool are reduced and preferably eliminated by the decoupling means. In this manner, a benign environment is provided for the sensor unit such that continuous and accurate readings may be obtained.
In a preferred embodiment the decoupling means is mechanically decoupled from the rotary motion of the drilling tool. The decoupling means therefore remains stationary, or near stationary, with respect to an Earth fixed reference frame. In this manner, the output of the sensors is improved and preferable perfected and in particular, gyroscopes may be utilised.
Preferably, the decoupling means and the sensor unit are positioned towards the second end of the main tool body. Thus, if the rotary steerable tool is caused to move away from the desired trajectory, by for example, rock mechanics, the sensor unit will be able to provide immediate indication of this.
By utilising said decoupling means, the vibratory forces experienced by the sensor unit are considerably lower than would be experienced by the sensor unit if placed in the BHA, above the rotary steerable tool. Thus, the sensor unit is able to provide accurate measurements when drilling is in progress.
In one embodiment, the main body of the rotary steerable drilling tool further comprises a flexible shaft, positioned within the main body, and a non-flexible shaft, positioned between the first end of the main body and the flexible shaft, wherein the sensor unit is positioned within the non-flexible shaft.
Preferably, the main body of the rotary steerable tool further comprises a rotationally stable platform positioned within the non-flexible shaft, wherein the sensor unit is positioned on the rotating platform. The stable platform is arranged to rotate in the contra direction in which the drill string and shafts of the rotary steerable tool are rotating. Thus the sensor unit may be kept substantially stationary with respect to the fixed Earth axis. A suitable rotary platform is described in WO 01/29372.
In a preferred embodiment said main tool body further comprises an outer housing and said sensor unit is positioned within the outer housing.
The outer housing of the rotary steerable tool is preferably stabilised and remains nominally static for much of the drilling process, turning only slowly as drilling progresses. For example, the rotary motion may be restrained by contact between a reference stabiliser, located along the outer body of the rotary steerable tool, and the wall of the bore hole. In addition, this continuous contact with the wall results in much of the shock and vibration being attenuated significantly, in comparison to the levels of motion that can normally be experienced by down-hole equipment whilst drilling is taking place. Hence, the levels of shock and vibration experienced by the inertial sensors are much attenuated which enables meaningful measurements to be obtained continuously throughout the drilling process.
Preferably, the sensor unit is an Inertial Measurement Unit (IMU). Preferably, the inertial measurement unit (IMU) comprises gyroscopic sensors together with accelerometers which measure angular rate and linear acceleration respectively. More preferably the IMU comprises orthogonal triads of linear accelerometers and gyroscopes.
Preferably, the rotary steerable tool further comprises a signal processor, which together with the IMU constitutes an inertial measurement system. This system may be configured either as an attitude and heading reference system to provide directional survey data, or as a full inertial navigation system (INS) in order to provide both directional and positional survey data.
The provision of continuous, accurate information concerning the direction and/or position of the rotary steerable drilling tool and/or drill bit by the use of a decoupling means enables the implementation of an automated guidance system using closed loop control. The computational capability necessary to implement such a system may be located either at the surface or within the bottom hole assembly. Depth and/or bore-hole path length information may be transmitted from the surface and combined with the inertial measurements concerning inclination and azimuth. These data may then be compared with a pre-planned trajectory. The pre-planned trajectory can be expressed in angular form as a function of path length, or as positional coordinates. The computational system then provides the bend unit, or steering system, with instructions to maintain the drill bit within the path limits of the pre-planned trajectory.
The Inertial Measurement Unit (IMU) can operate without magnetometers, and preferably does not comprise magnetometers. It is thus not usually susceptible to magnetic interference. This being the case, it can be located on the rotary steerable tool. By positioning the IMU on the rotary steerable tool, the relationship between the longitudinal axis of the IMU and the longitudinal axis of the rotary steerable will be known. Indeed in preferred embodiments, the axes will be the same. Thus the relationship between the measurements taken by the IMU and the direction and/or position of the rotary steerable tool will also be known enabling accurate determination of the direction and/or position of the rotary steerable drilling tool (and thus the drill bit). In addition, by placing the IMU on the rotary steerable tool, it is located closer to the drill bit than would be the case if it were placed in the BHA (as is the case for conventional MWD survey tools) above the rotary steerable system.
Alternatively, instead of deflecting said second end on the basis of the difference, said deflection means 70 deflects said second end in response to said difference.
The drive means may be any suitable mechanism for driving the rotary steerable tool. In particular however, the drive means may be a surface motor which is connected to the tool via the drill string. Rotary motion is transmitted from the surface, through the drill string, to the tool. Alternatively, the drive means may be a mud motor located in the Bottom Hole Assembly. The mud motor comprises an impeller which is driven by fluid which is pumped down the drill string from the surface. The rotary motion is then transmitted to the tool. Alternatively, the surface motor and mud motor may be used in combination to improve efficiency.
In a further aspect, the present invention provides a method of drilling bore holes comprising the steps of: connecting a steerable rotary drilling tool to a drill bit and a drive means; rotating the steerable rotary drilling tool using said drive means so as to cause the drill bit to rotate and commence drilling; estimating the direction and/or position of the drilling tool on the basis of the output of a sensor unit of the steerable rotary drilling tool; calculating the difference between the estimated direction and/or position and corresponding prestored direction and/or position information; and deflecting the steerable rotary drilling tool on the basis of said difference; wherein said estimating step includes a step of mechanically decoupling said sensor unit from a tool body of said steerable rotary drilling tool.
In yet a further aspect, the present invention provides a method of drilling bore holes comprising the steps of: connecting a steerable rotary drilling tool a to drill bit and a drive means; rotating the steerable rotary drilling tool using said drive means so as to cause the drill bit to rotate and commence drilling; estimating the direction and/or position of the drilling tool on the basis of the output of a sensor unit of the steerable rotary drilling tool, the sensor unit being mechanically decoupled from the tool body of said steerable rotary drilling tool; calculating the difference between the estimated direction and/or position and corresponding prestored direction and/or position information; and deflecting the steerable rotary drilling tool on the basis of said difference.
The present invention will now be described by way of example only and with reference to the accompanying drawings in which:
a, 1b, 1c and 1d are schematic representations of the well-bore guidance system in four alternative embodiments of the present invention;
a, 1b, 1c and 1d show a rotary steerable tool 1 connected to a drill bit 3 in preferred embodiments of the present invention. Like features are referenced with like numerals. The closed loop control system will be described in more detail below, however first the positioning of the sensors will be described.
As noted above the mechanical decoupling of the sensors from the motion and vibration of the drilling tool allows continuous and accurate measurements to be obtained.
The first embodiment is shown in
The second embodiment is shown in
The third embodiment is shown in
The fourth embodiment is shown in
The sensors may also be placed on a rotating platform positioned in drill string immediately behind the drilling tool.
The rotary steerable tool comprises an inertial measurement unit (IMU) 4, a flexible shaft 5 and an outer housing 6. The IMU provides measurements of acceleration and angular rate about three orthogonal acceleration axes 7 and three orthogonal gyro axis 8 respectively.
A computer (not shown) calculates on the basis of these measurements, the direction, i.e. inclination and azimuthal deviation, and/or the position of the IMU. The computer can also calculate the velocity of the IMU. Given that the spatial relationship between the IMU and the drill bit is known, the calculations of spatial position and velocity can be extrapolated to provide a measure of drill bit direction, position and velocity. The tool face deflection angle can also be calculated. The IMU and computer together form an inertial measurement system. This system may be configured either as an attitude and heading reference system to provide directional survey data, or as a full inertial navigation system (INS) in order to provide both directional and positional survey data. The direction and/or position of the drill bit are calculated with respect to a pre-determined reference frame. In addition, the computer may be provided with depth/well bore hole path length information. In full inertial navigation mode, depth information may be used to obtain accurate co-ordinate position data. By combining the inertial system data with independent depth measurements, it is possible to bound the growth of inertial system error propagation.
Thus by utilising an Inertial Measurement System, which provides continuous and accurate information concerning the direction and/or position of the drill bit, and comparing this information with pre-planned well bore trajectory information, a closed loop control system for the automatic guidance of rotary steerable tools is achieved.
In the embodiment in which only direction calculations are used, the estimated inclination and azimuth readings at a given well depth/bore hole path length are compared with a stored profile of these quantities corresponding to the required well profile. Steering commands are then generated in proportion to the difference between these estimates. The differences between the desired and estimated inclination and azimuth are resolved into steering tool axes, using the estimated tool face angle, to form the signals to be passed to the bend unit of the rotary steerable tool.
In the embodiment in which position calculations are used, the position estimates, which may be generated in a local vertical geographic reference frame, are compared with the desired trajectory profile specified in the same coordinate frame, as a function of well depth. In vector form:
ΔxR(d)={circumflex over (x)}R (d)−xR(d)
where xR(d)=reference trajectory position at depth d, specified in reference axes
{circumflex over (x)}R (d)=estimated position at depth d, specified in reference axes
ΔxR(d)=position error depth d, specified in reference axes
The differences between the estimated and desired positions are transformed into well bore axes using the attitude estimates generated by the inertial measurement unit, to form:
where CRW (d)=direction cosine matrix relating reference and well bore axes
ΔxW (d)=position error at depth d, specified in well bore axes
Δx, Δy, Δz=components of position error
The z axis of the well bore coordinate frame (xyz) is coincident with the along-hole axis of the well, and the x and y axes are perpendicular to z and to each other. Steering commands (α and β) are then derived as a function of the lateral positional errors specified (Δx and Δy) in well bore axis:
α=KαΔx
β=KβΔy
Other control strategies may be adopted, rather than the simple form shown here. For example, steering signals may be derived taking into account the rates of change of the position error components.
In practice, the closed loop operation would include activation or reaction limits which could be specified or changed as required. This feature would inhibit the response of the control system to small measurement variations, thus suppressing mico-tortuosity in the drilled well path, the objective being to provide a smooth well path to the target location. The activation limit settings will be governed by prevailing drilling conditions and formation effects.
The estimates 38 are first fed into a Coriolis correction means 39, the output of which is added by means 40 to the input of the navigation computation means forming a first feed back loop. The INS velocity estimates are second fed into a velocity integration means 41 which produces INS position estimates 42. The position estimates are first fed into a gravity computation means 43 the output of which is added by means 44 to the input of the navigation computation means forming a second feed back loop. The INS position estimates are also used to compute the components of Earth's rate which are fed into the attitude computation means. Finally the INS position estimates are output from the INS to provide positional information.
In order to limit, or bound, the growth of errors in the INS arising as a result of instrument biases and other errors in the sensor measurements, independent measurements of bore hole path length may be used. These measurements are compared with estimates of the same quantities derived from the INS outputs and used to correct the INS as indicated in
As described above, the IMU provides measurements of acceleration and angular rate about three orthogonal axes. This is typically achieved using three single axis accelerometers and three single axis gyroscopes, the axes of which are mutually orthogonal. Alternatively, the three single axis gyroscopes may be replaced by two dual-axis gyroscopes. Whilst it is often the case that the sensitive axes of the inertial sensors are configured to be perpendicular to one another, this is not essential, and a so-called skewed sensor configuration may be adopted. Provided the sensitive axis of one of accelerometers and one of the gyroscopes does not lie in the same plane as the sensitive axes of the other two accelerometers and gyroscopes respectively, it is possible to compute the required readings about three mutually orthogonal axes.
In addition to the survey data produced by the IMU system described above, other survey data generated by a conventional MWD survey tool located further up the tool string may be used in correlation with the IMU calculations. These data would provide additional survey checks and an increased confidence in the calculated well path position.
Furthermore, it will be appreciated that sensors other than an IMU may be used to achieve the measurements required to implement the present invention. The main requirements for any such sensors being that they generate measurements which can be used to calculate direction or position.
Although the present invention has been described for use with a drill string, driven from the surface, it will be appreciated that other drive mechanisms may also be used in addition to or in place of the drill string/surface drive mechanism. For example, additional drill bit rotation may also be accomplished by means of a downhole motor placed within the Bottom Hole Assembly (BHA) providing an alternative or additional means of bit rotation. In particular, a mud motor of the sort described above may be utilised.
It will be appreciated that the invention described above may be modified.
| Number | Date | Country | Kind |
|---|---|---|---|
| 0415453.0 | Jul 2004 | GB | national |
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/GB2005/002668 | 7/6/2005 | WO | 00 | 10/12/2007 |
| Publishing Document | Publishing Date | Country | Kind |
|---|---|---|---|
| WO2006/005916 | 1/19/2006 | WO | A |
| Number | Name | Date | Kind |
|---|---|---|---|
| 3713500 | Russell | Jan 1973 | A |
| 5220963 | Patton | Jun 1993 | A |
| 6092610 | Kosmala et al. | Jul 2000 | A |
| 6158529 | Dorel | Dec 2000 | A |
| 6233524 | Harrell et al. | May 2001 | B1 |
| 6234259 | Kuckes et al. | May 2001 | B1 |
| 6467557 | Krueger et al. | Oct 2002 | B1 |
| 6714870 | Weston et al. | Mar 2004 | B1 |
| 20020005297 | Alft et al. | Jan 2002 | A1 |
| 20020133958 | Noureldin et al. | Sep 2002 | A1 |
| 20040084219 | Moore et al. | May 2004 | A1 |
| Number | Date | Country |
|---|---|---|
| 0594418 | Apr 1994 | EP |
| 0806542 | Nov 1997 | EP |
| 2392931 | Mar 2004 | GB |
| WO0129372 | Apr 2001 | WO |
| Number | Date | Country | |
|---|---|---|---|
| 20080128171 A1 | Jun 2008 | US |
