Title of Invention | SYSTEM AND METHOD FOR FLUID FLOW OPTIMIZATION IN A GAS - LIFT OIL WELL |
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Abstract | The present invention relates to a system and method for fluid flow optimization in a gas-lift oil well. A controllable gas-lift well having gas-lift valves and sensors for detecting flow regime is provided. The well uses production tubing and casing to communicate with and power the controllable valve from the surface. A singnal impedance apparatus in the form of induction chokes at the surface and downhole electricaly isolate the tubing from the casing. A high band-width adaptable spread spectrum communication system is used to communicate between the controllable valve and the surface. Sensors, such as pressure, temperature and acoustic sensors, may be provided downhole to more accurately assess downhole conditions and in partricular, the flow regime of the fluid within the tubing, Operating conditions, such as gas injection rate, back pressure on the tubing, and position of downhole controllable valves are varied depending on flow regime, downhole conditions, Oil production, gas usage and availability, to optimize production, An artificial Neural Network (ANN) is trained to detect a Taylor flow regime using downhole acoustic sensors, plus others sensors as desired. The detection and control system and method therof is useful in many applications involving multi-phase flow in a conduit. |
Full Text | SYSTEM AND METHOD FOR FLUID FLOW- OPTIMIZATION IN A GAS-LIFT OIL WELL BACKGROUND OF THE INVENTION The present invention relates to a system and method for optimizing fluid flow in a pipe and in particular, flow in a gas-lift well. DESCRIPTION OF RELATED ART Gas-lift wells have been in use since the 1800"s and have proven particularly useful in increasing efficient rates of oil production where the reservoir natural lift is insufficient. See Brown, Connolizo and Robertson, West Texas Oil Lifting Short Course and H.W. Winkler, "Misunderstood or Overlooked Gas-Lift Design and Equipment Considerations," SPE, P. 351 (1994). Typically, in a gas-lift oil well, natural gas produced in the oil field is compressed and injected in the annular space between the casing and tubing and directed from the casing into the tubing to provide a "lift" to the tubing fluid column for production of oil out of the tubing. Although the tubing can be used for the injection of the lift-gas and the annular space used to produce the oil, this is rare in practice. Initially, the gas-lift wells injected the gas at the bottom of the tubing, but of course with deep wells this requires excessively high kick off pressures and methods have been devised to inject the gas into the tubing at various depths in the wells. See e.g., U.S. Patent No. 5,267,469. The most common type of gas-lift well uses mechanical, bellows-type gas-lift valves attached to the tubing to regulate the flow of gas from the annulus between the casing and the tubing into the tubing. See U.S. Patent Nos. 5,782,261, and 5,425,425. In a typical bellows-type gas-lift valve, the bellows is preset or pre-charged to a certain pressure to allow operation of the valve, permitting communication of gas out of the annulus into the tubing at the pre-charged pressure. The pressure charge of each valve is designed by the well engineer depending upon the position of the valve in the well, pressure head, the conditions of the well, and a host of other factors. The typical bellows-type gas-lift valve has a pre-charge for regulating the gas flow from the annulus outside the tubing to lift the oil. Several problems are common with such typical bellows-type gas-lift valves. First, the bellows often loses its charge allowing the valve to fail in the closed position or operate at other than the design goal. Another common failure is the erosion around the valve seat and deterioration of the ball stem in the valve which often leads to partial failure of the valve or at least inefficient production. Because the gas flow through a gas-lift valve is often not continuous at a steady state, but rather exhibits a certain amount of hammer and chatter as the ball valve is in use, valve and seat degradation is common. Failure or inefficient operation of bellows-type valves leads to corresponding inefficiencies in operation of a typical gas-lift well. In fact, it is estimated that well production is at least 5-15% less than optimum because of valve failure or operational inefficiencies. It would, .therefore, be a significant advance if a system and method were devised which overcame the inefficiency of conventional bellows-type gas-lift valves. Several methods have been devised to place controllable va.lves downhole on the tubing string but all such known devices typically use an electrical cable along the tubing string to power and communicate with the gas-lift valves. It is, of course, highly undesirable and in practice difficult to use a cable along the tubing string either integral with the tubing string or spaced in the annulus between the tubing and the casing because of the number of failure mechanisms present in such a system. Other methods of communicating within a borehole are described in U.S. Patent Nos. 5,493,288; 5,576,703; 5,574,374; 5,467,083; 5,130,7.06. U.S. Patent No. 4,83",644 describes a method and system for wireless two-way communications in a cased borehole having a tubing string. However, this system describes a downhole toroid antenna for coupling electromagnetic energy in a waveguide TEM mode using the-annulus between the casing and the tubing. This toroid antenna uses an electromagnetic wave coupling which requires a substantially nonconductive fluid (such as refined, heavy oil) in the annulus between the casing and the tubing and a toroidal cavity and wellhead insulators. Therefore, the method and system described in U.S. Patent No. 4,839,644 is expensive, has problems with brine leakage into the casing, and is difficult to use as a scheme for a downhole two-way communication. Other downhole communication schemes such as mud pulse telemetry (U.S. Patent Nos. 4,648,471; 5,887,657) have shown successful communication at low data rates but are of limited usefulness as a communication scheme where high data rates are required or it is undesirable to have complex, mud pulse telemetry equipment downhole. Still other downhole communication methods have been attempted, see U.S. Patent Nos. 5,467,083; 4,739,325; 4,578,675; 5,883,516; and 4,4 68,665 as well as downhole permanent sensors and control systems: U.S. Patent Nos. 5,730,219; 5,662,165; 4,972,704; 5,941,307; 5,934,371; 5,278,758; 5,134,285; 5,001,675; 5,730,219; 5,662,165. >) It is generally known that in a gas-lift well, an increase of compressed gas injected downhole (i.e. lift-gas) does not linearly correspond to the amount of oil produced. That is, for any particular well under a particular set of operating conditions, the amount of gas injected can be optimized to produce the maximum oil. Unfortunately, using conventional bellows type valves, the opening pressure of the gas-lift bellows type valves is preset and the primary control of the well is through the amount of gas injected at the surface. Feedback to determine optimum production of the well can take many hours and even days. It is also generally known that in two-phase flow regimes - such as in a gas-lift well - several flow regimes exist with varying efficiencies. See, A. van der Spek and A. Thomas, "Neural Net Identification of Flow Regime using Band Spectra of Flow Generated Sound", SPE 50640, October 1998. However, while -operating in a particular flow regime is known to be desirable, it has largely been considered impossible to practically implement. It would, therefore, be a significant advance in the operation of gas-lift wells if an alternative to the conventional bellows type valve were provided, in particular, if sensors for determining flow characteristics in the well could work with controllable gas lift valves and surface controls to optimize fluid flow and in a gas-lift well. The method and system according to the preamble of claims 1, 10 and 14 are known from European patent EP 0721053. In the known method and system a sensor mounted below a gas-lift valve detects characteristics of a generally single phase flow of crude oil below a gas-lift injection valve, which characteristics are used to control the opening of the valve such that an optimum amount of lift gas is injected to reduce the density of the crude oil and lift gas mixture that is created at and above the lift gas injection point. US patent 5,353,627 discloses a method for detecting a flow regime in a multiphase fluid flow by means of a passive acoustical detector. US patent 6,012,015 discloses an automated downhole flow control system for a multilateral well system comprising acoustic and other sensors for evaluating formation parameters and influx of water. Generally, it would be a significant advance to be able to detect the flow regime in a two-phase flow conduit, and to control the operation to remain in a desirable phase. The references cited herein are incorporated by reference. SUMMARY OF THE INVENTION The method and system according to the invention are characterized by the characterizing features of claims 1, 10 and 14. The problems outlined above are largely solved by the system and method in accordance with the present invention for determining a flow regime and controlling the flow characteristics to attain a desirable regime. In the preferred application, the controllable gas-lift well includes a cased wellbore having a tubing string positioned within and longitudinally extending within the casing. A controllable gas-lift valve is coupled to the tubing to control the gas injection between the interior and exterior of the tubing, more specifically, between the annulus between the tubing and the casing and the interior of the tubing. The controllable gas-lift valve and sensors are power are powered and controlled from the surface to regulate such tasks as the fluid communication between the annulus and the interior of the tubing and the amount of gas injected at the surface. Communication signals and power are sent from the surface using the tubing and casing as conductors. The power is preferably a low voltage AC current around 60 Hz. In more detail, a surface computer includes a modem with a communication signal imparted to the tubing and received at a modem downhole connected to the controllable gas-lift valve. Similarly, the modem downhole can communicate sensor information to the system computer. Further, power is input into the tubing string and received downhole to control the operation of the controllable gas-lift valve and to power the sensor. Preferably, the casing is used as the ground return conductor. Alternatively, a distant ground may be used as the electrical return. The ground return path is provided from the controllable gas-lift valve via a conductive centralizer around the tubing which is insulated in its contact with the tubing, but in electrical contact with the casing. In enhanced forms, the controllable gas-lift well includes one or more sensors downhole which are preferably in contact with the downhole modem and i-wituuuiixucite wicn the surface computer. In addition acoustic, such sensors as temperature, pressure, hydrophone, geophone, valve position, flow rates, and differential pressure gauges are advantageously used in many situations. The sensors supply measurements to the modem for transmission to the surface or directly to a programmable interface controller for determining the flow regime at a given location and operating the controllable gas-lift valve and surface gas injection for controlling the fluid flow through the gas-lift valve. Preferably, ferromagnetic chokes are coupled to the tubing to act as a series impedance to current flow on the tubing. In a preferred form, an upper ferromagnetic choke is placed around the tubing below the tubing hanger, and the current and communication signals are imparted to the tubing below the upper ferromagnetic choke. A lower ferromagnetic choke is placed downhole around the tubing with the controllable gas-lift valve electrically coupled to the tubing above the lower ferromagnetic choke, although the controllable gas-lift valve may be mechanically coupled to the tubing below the lower ferrite choke. It is desirable to mechanically place the operating controllable gas-lift valve below the lower ferromagnetic choke so that the borehole fluid level is below the choke. Preferably, a surface controller (computer) is coupled via a surface master modem and the tubing to the downhole slave modem of the controllable gas-lift valve. The surface computer can receive measurements from a variety of sources, such as the downhole sensors, measurements of the oil output, and measurements of the compressed gas input to the well (flow and pressure). Using such measurements, the computer can compute an optimum position of a controllable gas valve, more particularly, the optimum amount of the gas injected from the annulus inside the casing through each controllable valve into the tubing. Additional parameters may be controlled by the computer, such as controlling the amount of compressed gas input into the well at the surface, controlling back pressure on the wells, controlling a porous fret or surfactant injection system to foam the oil, and receiving production and operation measurements from a variety of other wells in the same field to optimize the production of the field. The ability to actively monitor current conditions downhole, coupled with the ability to control surface and downhole conditions, has may advantages in a gas-lift well. Conduits such as gas-lift wells have four broad regimes of fluid flow, namely bubbly, Taylor, slug and annular flow. The most efficient production (oil produced versus gas injected) flow regime is the Taylor flow regime. The downhole sensors of the present invention enable the detection of Taylor flow. The above referenced control mechanisms-surface computer, controllable valves, gas input, surfactant injection, etc. - provide the ability to attain and maintain Taylor flow. In enhanced forms, the downhole controllable valves may be operated independently to attain localized Taylor flow. In the preferred embodiment, all of the gas-lift valves in the well are of the controllable type in accordance with the present invention and may be independently controlled. It is desirable to lift the oil column from a point in the borehole as close as possible to the production packer. That is, the lowest gas-lift valve is the primary valve in production. The upper gas-lift valves are used for set off of the well during production initiation. In conventional gas-lift wells, these upper valves have bellows pre-set with a 200 psi margin of error to ensure the valves close after set off. This means lift pressure is lost downhole to accommodate this 200 psi loss per valve. Further, such conventional valves often leak and fail to fully close. Use of the controllable valves of the present invention overcomes such shortcomings. Construction of such a controllable gas-lift well is designed to be as similar to conventional construction methodology as possible. That is, after casing the well, a packer is typically set above the production zone. The tubing string is then fed through the casing into communication with the production zone. As the tubing string is built at the surface, a lower ferrite choke is placed around one of the conventional tubing strings for positioning above the downhole packer. In the sections of the tubing strings where it is desired, a gas-lift valve and one or more sensors are coupled to the string. In a preferred form, a side pocket mandrel for receiving a slickline insertable and retractable gas-lift valve or sensor is used. With such configuration, either a controllable gas-lift valve in accordance with the present invention can be inserted in the side pocket mandrel or one or more sensor packages can be used. Alternatively, the controllable gas-lift valve or sensors may be tubing conveyed. The tubing string is built to the surface where a ferromagnetic choke is again placed around the tubing string below the tubing hanger. Communication and power leads are then connected through the wellhead feed through to the tubing string below the upper ferromagnetic choke. In an alternative form, a sensor and communication pod is inserted without the necessity of including a controllable gas-lift valve. That is, an electronics module having pressure, temperature or acoustic sensors or other sensors, power supply, and a modem is inserted into a side pocket mandrel for communication to the surface computer to determine flow regime using the tubing and casing conductors. Alternatively, such electronics modules may be mounted directly on the tubing (tubing conveyed) and not be configured to be wireline replaceable. If directly mounted to the tubing an electronic module or a controllable gas-lift valve may only be replaced by pulling the entire tubing string. With only sensors placed downhole, measurements aire communicated to the surface and surface parameters (e.g. compressed gas input) are regulated to obtain a desirable downhole flow regime. BRIEF DESCRIPTION OF THE DRAWINGS FIG. 1 is a schematic of the controllable gas-lift well in accordance with a preferred embodiment of the present invention; FIG. 2 is a schematic detail of a tubing string in a cased borehole illustrating the disposition of a side pocket mandrel on the tubing string; FIG. 3 is a series of fragmentary, vertical sectional views illustrating flow patterns in two-phase vertical (upward) flow wherein FIG. 3A illustrates bubbly flow, FIG. 3B illustrates slug flow FIG. 3C illustrates churn flow, and FIG. 3D illustrates annular flow; FIGS. 4A-4D illustrate flow patterns in horizontal two-phase flow wherein FIG. 4A illustrates annular dispersed flow, FIG. 4B illustrates stratified wavy flow, FIG. 4C illustrates slug or intermittent flow, and FIG. 40 illustrates dispersed bubble flow; FIG. 5 is a graph plotting quantity of compressed gas vs. tubing pressure and depicts the four flow regimes typically encountered in a gas-lift well, namely bubbly, Taylor, slug flow, and annular flow; FIG. 6 is an enlarged schematic illustrating a controllable gas-lift valve received in a wireline retrievable, side pocket mandrel; FIGS- 7A-7C are vertical sectional views of a preferred form of the controllable valve in a cage configuration; FIG. 8 is an enlarged vertical section schematic, depicting an electronics module containing sensors coupled to the tubing string separate from the controllable valve; FIG. 9 is a depiction of the equivalent circuit diagram of the controllable gas-lift well of FIG. 1; FIG. lOA is an enlarged schematic illustrating a controllable valve permanently coupled to the tubing string; FIG. lOB is an enlarged vertical sectional view of a controllable gas-lift valve, illustrating an alternative embodiment of the controllable valve; FIG. 11 is a schematic diagram depicting the surface computer in communication with the electronics of the controllable gas-lift valve; FIG. 12 is a system block diagram of an electronics power and control system; and FIG. 13 is a block diagram of a feed forward, bank propagation neural network for interpretation of acoustic date. DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS 1. Description of Flow Regimes Without a flow regime classification, it is hard to quantify fluid flow rates of two-phase flow in a conduit. The conventional way of flow regime classification is by visual observation of flow in a conduit by a human observer. Although downhole video surveys are commercially available, visual observation of downhole flow is not standard practice in (horizontal well, production logging, as it requires a special wireline (optical fiber cable). Moreover, downhole video surveys can only be successful in transparent fluids; either gas wells or wells killed with clear kill fluid. In oil wells, an alternative to visual observation for classifying the flow regime is needed. All flow regimes produce their own characteristic sounds. A trained human observer can classify flow regime in a pipe by aural rather than visual observations. Contrary to video surveys, sound logging services are available from various cased hole wireline service providers. The traditional use of such sound logs is to pinpoint leaks in either casing or tubing strings. In addition to the sound logs recorded, the surface control panel is equipped with amplifiers and speakers that allow audible observation of downhole produced sounds. The sound log typically is a plot vs. along hole depth of (uncalibrated) sound pressure level after passing the sound signal through 5 different high pass filters (noise cuts: 200 Hz, 600 Hz, 1000 Hz, 2000 Hz and 4000 Hz). In principle, the logging engineer, based on aural observation of the downhole sounds, could carry out flow regime classification. This procedure, however, is impractical: it is prone to errors, it cannot be reproduced from recorded logs (the sound is not normally recorded on audio tape) and it relies on the experience of the specific engineer. Successful application of neural.net classification of flow regime from sound logs in the field brings several benefits to the business. First of all it will allow the application of the correct, flow regime specific, hydraulic model to the task of evaluating horizontal well, two-phase flow production logs. Secondly, it allows a more constrained consistency check on recorded production logging data. Last it alleviates the need to predict flow regime using hydraulic stability criteria from first principles thereby reducing computational loads by at least a factor of 10 resulting in faster turn around times. Flow Regimes "Two-phase flow is the interacting flow of two phases, liquid, solid or gas, where the interface between the phases is influenced by their motion" (Butterworth and Hewitt, 1979). Many different flow patterns can result from the changing form of the interface between the two phases. These patterns depend on a variety of factors; for instance the phase flow rates, the pressure, and the diameter and inclination of the pipe containing the flow in question, etc. Flow regimes in vertical upward flow is illustrated in FIG. 3 includes: Bubble flow: A dispersion of bubbles in a continuum of liquid. Intermittent or Slug flow: The bubble diameter approaches that of the tube. The bubbles are bullet shaped- Small bubbles are suspended in the intermediate liquid cylinders. Churn or froth flow: A highly unstable flow of an oscillatory nature, whereby the liquid near the pipe wall continuously pulses up and down. Annular flow: A film of liquid flows on the wall of the pipe and the gas phase flows in the center. TU^ove flow patterns are obtained with increasing gas rate. For gas wells annular flow is expected over a major part of the tubing whereas for oil wells intermittent flow prevails in the upper part of the tubing. At tubing intake conditions bubble flow is predominantly present, hence in the tubing, because of the release of associated gas from oil when the pressure falls a transition from bubble flow to intermittent flow occurs. Flow regimes in horizontal flow are illustrated in FIG. 4 and are described below: Bubble flow: The bubbles tend to float at the tope in the liquid. -r Stratified flow: The liquid flows along the bottom of the pipe and the gas flows on top. Intermittent or Slug flow: Large frothy slugs of liquid alternate with large gas pockets. Annular flow: A liquid ring is attached to the pipe wall with gas blowing through. " usually, the layer at the bottom is very much thicker than the one at the top. Another flow regime has been identified - Taylor flow - which occurs between Bubbly and Slug flow of FIGS. 3A and 3B and has characteristics of each. More in particularly, as illustrated in FIG. 5, Taylor flow is a most desirable flow regime for maximizing oil output for a quantity of gas injected. Although the preferred embodiment is primarily concerned with achieving Taylor flow in a vertical oil well, the principles are applicable to horizontal wells (FIG. 4) and most two-phase flows in a conduit. Superficial velocity is the ratio of volumetric flow rate at line conditions, Q, to the cross-section of the pipe, A, such that: Q vs=- (1) A Superficial velocity is the velocity that a phase would have had if it were the only phase in the pipe. Gas volume fraction (GVF) is the superficial gas velocity divided by the sum of the superficial gas and superficial liquid velocities. GVF= ^^^ (2) Vse^st The gas volume fraction is pressure dependent. Note that in the flow loop experiments gas flow rate is expressed at normal conditions (Nm-^/h) . A convenient and illustrative way to depict flow regimes vs. flow rates is to map flow regime on a two dimensional plane with superficial gas velocity on the horizontal axis and superficial liquid velocity on the vertical axis for a given pipe inclination, see FIG. 3. In theory, 8 variables are needed to define a flow regime in a pipe. In an angle dependent flow map representation, only 3 variables are used. In this case, the approach is justified because the 3 flow map variables, i.e. pipe inclination angle, superficial gas velocity and superficial liquid velocity are the only variables that were changed in the course of the studies. All other variables, i.e. gas and liquid density and viscosity, surface tension, pipe diameter and pipe roughness are fixed (Wu, Pots, Hollenberg, Meerhoff, "Flow pattern transitions in two-phase gas/condensate flow at high pressures in an 8 inch horizontal pipe," Proc. of the Third International Conf. on Multiphase-Phase Flow, The Hague, The Netherlands, 18-20 May, pp. 13-21, 1987; Oliemans, Pots, Trompe, "Modeling of annular dispersed two-phase flow in vertical pipes," J. Multiphase Flow, 12:711-732, 1986). An exemplary flow map covers 3 orders of magnitude for both the gas and the liquid flow rate. At 10 m/s liquid superficial velocity, a 4-inch pipe will sustain a flow rate of approximately 10000 barrels of liquid per day if the liquid were the only fluid flowing in the pipe. Thus such a flow map covers all situations that are of practical use in oilfield application. Since gas volume fraction is the ratio of superficial gas velocity to the sum of superficial gas and superficial liquid velocity, lines of constant gas volume fraction appear on the flow map as straight parallel lines of 45-degree slope. the 50% GVF line is the line passing through the points (10,10) and (0.01,0.01). To the right of this line higher gas volume fractions occur, whereas to the left the gas volume fraction decreases, Sound Measurements Sound is rarely made up of only one frequency. Hence, in order to analyze it, a whole range of frequencies should be investigated. The chosen frequency spectrum can be divided into contiguous bands (Pierce, 1981) such that: fni"^)=fj,{n + l) (3) and subsequently /u(n + l)=/L(n + 2) (4) where the n^^ band is limited by a lower frequency fjjin) and an upper frequency /^(n). The bands are said to be proportional if the ratio fu(n)/fL(n) is the same for each band. An octave is a band for which /u= 2/L (5) i.e. the top frequency is twice the lower limit frequency of the band. In the same way, a one third octave band is one where any proportional band is defined by its center frequency. This is given by /o=V^A ^"^^ The standard 1/3 octave-partitioning scheme (ANSI S.1.6-1967 (R 1976)) uses the fact that ten 1/3 octave bands are nearly a decade. Standard 1/3 octave bands are such that: f^n+10=10f^{n) (8) i.e. 1, 10, 100, 1000 and so on are some of the standard 1/3 octave center frequencies. A graphical display of 1/3 octave band numbers vs. frequency can be made. On a logarithmic scale 1/3 octave bands are equidistant and are of the same width. ; j Two analysis ranges used by recording equipment are th"e 100 kHz and 1 kHz ranges. The 100 kHz range covers the bands 20 through 49. The 1 kHz range covers the bands 1 to 28. Apart from 1/3 octave spectra and octave spectra, an alternative partitioning scheme using decades is also possible. The center frequencies of two adjacent decade bands have ratio of 10. The signal magnitude in any given band is expressed as sound pressure level. The sound pressure level (SPL) has a logarithmic scale and is measured in decibels (dB) (Kinsler et al., 1982). If p is the sound pressure then:
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in-pct-2002-1130-che abstract.pdf
in-pct-2002-1130-che claims duplicate.pdf
in-pct-2002-1130-che claims.pdf
in-pct-2002-1130-che correspondence others.pdf
in-pct-2002-1130-che correspondence po.pdf
in-pct-2002-1130-che description (complete) duplicate.pdf
in-pct-2002-1130-che description (complete).pdf
in-pct-2002-1130-che drawings duplicate.pdf
in-pct-2002-1130-che drawings.pdf
in-pct-2002-1130-che form-1.pdf
in-pct-2002-1130-che form-19.pdf
in-pct-2002-1130-che form-26.pdf
in-pct-2002-1130-che form-3.pdf
in-pct-2002-1130-che form-5.pdf
in-pct-2002-1130-che petition.pdf
Patent Number | 212836 | |||||||||||||||
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Indian Patent Application Number | IN/PCT/2002/1130/CHE | |||||||||||||||
PG Journal Number | 07/2008 | |||||||||||||||
Publication Date | 15-Feb-2008 | |||||||||||||||
Grant Date | 17-Dec-2007 | |||||||||||||||
Date of Filing | 24-Jul-2002 | |||||||||||||||
Name of Patentee | SHELL INTERNATIONALE RESEARCH MAATSCHAPPIJ B.V | |||||||||||||||
Applicant Address | Carel van Bylandtlaan 30, NL-2596 HR The Hague | |||||||||||||||
Inventors:
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PCT International Classification Number | E21B 43/12 | |||||||||||||||
PCT International Application Number | PCT/EP2001/000740 | |||||||||||||||
PCT International Filing date | 2001-01-22 | |||||||||||||||
PCT Conventions:
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