OA11483A - Inflow detection apparatus and system for its use. - Google Patents
Inflow detection apparatus and system for its use. Download PDFInfo
- Publication number
- OA11483A OA11483A OA1200000241A OA1200000241A OA11483A OA 11483 A OA11483 A OA 11483A OA 1200000241 A OA1200000241 A OA 1200000241A OA 1200000241 A OA1200000241 A OA 1200000241A OA 11483 A OA11483 A OA 11483A
- Authority
- OA
- OAPI
- Prior art keywords
- source
- sensor
- région
- aecording
- well
- Prior art date
Links
- 238000001514 detection method Methods 0.000 title description 2
- 238000000034 method Methods 0.000 claims abstract description 26
- 239000012530 fluid Substances 0.000 claims abstract description 19
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 13
- 238000013480 data collection Methods 0.000 claims abstract description 5
- 238000012544 monitoring process Methods 0.000 claims abstract description 3
- 230000003287 optical effect Effects 0.000 claims description 11
- 238000010438 heat treatment Methods 0.000 claims description 3
- 239000000835 fiber Substances 0.000 description 14
- 238000004519 manufacturing process Methods 0.000 description 12
- 238000005755 formation reaction Methods 0.000 description 10
- 239000007789 gas Substances 0.000 description 6
- 238000005259 measurement Methods 0.000 description 6
- 238000000253 optical time-domain reflectometry Methods 0.000 description 5
- 238000005516 engineering process Methods 0.000 description 4
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 4
- 239000007788 liquid Substances 0.000 description 3
- 230000008569 process Effects 0.000 description 3
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 2
- 238000004364 calculation method Methods 0.000 description 2
- 230000008859 change Effects 0.000 description 2
- 238000005253 cladding Methods 0.000 description 2
- 238000005553 drilling Methods 0.000 description 2
- 239000001257 hydrogen Substances 0.000 description 2
- 229910052739 hydrogen Inorganic materials 0.000 description 2
- UFHFLCQGNIYNRP-UHFFFAOYSA-N Hydrogen Chemical compound [H][H] UFHFLCQGNIYNRP-UHFFFAOYSA-N 0.000 description 1
- 238000001069 Raman spectroscopy Methods 0.000 description 1
- 230000008901 benefit Effects 0.000 description 1
- 238000000576 coating method Methods 0.000 description 1
- 238000010276 construction Methods 0.000 description 1
- 238000011161 development Methods 0.000 description 1
- 230000018109 developmental process Effects 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 230000005520 electrodynamics Effects 0.000 description 1
- 239000011521 glass Substances 0.000 description 1
- 239000003365 glass fiber Substances 0.000 description 1
- 150000002431 hydrogen Chemical class 0.000 description 1
- 239000011159 matrix material Substances 0.000 description 1
- 239000000203 mixture Substances 0.000 description 1
- 230000005693 optoelectronics Effects 0.000 description 1
- 239000002245 particle Substances 0.000 description 1
- 230000000149 penetrating effect Effects 0.000 description 1
- 230000035699 permeability Effects 0.000 description 1
- 239000003208 petroleum Substances 0.000 description 1
- 238000012545 processing Methods 0.000 description 1
- 238000007670 refining Methods 0.000 description 1
- 238000002310 reflectometry Methods 0.000 description 1
- 229960001866 silicon dioxide Drugs 0.000 description 1
- 235000012239 silicon dioxide Nutrition 0.000 description 1
- 239000000377 silicon dioxide Substances 0.000 description 1
- 230000000638 stimulation 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
- E21B47/10—Locating fluid leaks, intrusions or movements
-
- 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
- E21B47/10—Locating fluid leaks, intrusions or movements
- E21B47/103—Locating fluid leaks, intrusions or movements using thermal measurements
-
- 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
- E21B47/10—Locating fluid leaks, intrusions or movements
- E21B47/107—Locating fluid leaks, intrusions or movements using acoustic means
Landscapes
- Physics & Mathematics (AREA)
- Geology (AREA)
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Mining & Mineral Resources (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Fluid Mechanics (AREA)
- Environmental & Geological Engineering (AREA)
- Geophysics (AREA)
- Geochemistry & Mineralogy (AREA)
- Acoustics & Sound (AREA)
- Testing Or Calibration Of Command Recording Devices (AREA)
- Geophysics And Detection Of Objects (AREA)
- Measuring Volume Flow (AREA)
- Nozzles (AREA)
- Examining Or Testing Airtightness (AREA)
Abstract
There is provided a method for monitoring fluid flow within a region to be measured of a subterranean formation, said method comprising placing at least one source within said subterranean formation; placing at least one sensor within said region to be measured, wherein each said at least one sensor is adjacent to at least one source such that said sensor measures changes to said fluid caused by said source; and providing at least one means for transmitting data from each said at least one sensor to at least one data collection device, said at least one data collection device capable of communicating with an operator.
Description
01 1 483 - î -
INFLOW DETECTION APPARATUS AND SYSTEM FOR ITS USE
Field of the Invention
This invention relates to a method for measuringfluid flow in a subterranean formation; in particularmeasurements of flow rates of liquids, gases, and mixed 5 fluids in subterranean formations.
Background
Recent developments in the oil drilling industry ofwell bore construction techniques such as horizontalwells and multi-lateral wells, présent new challenges to 10 the completion and réservoir engineering disciplines. " High rate horizontal wells in deep water conditions further push the technology tools the petroleum engineerhas available to safely and prudently produce theréservoirs. 15 Classical methods of réservoir monitoring assume the permeability ("K") and height ("H") of the zonecontributing to the production of the well is known.
This "KH" is often confirmed with production logs on aperiodic basis and is typically considered constant. The 20 KH of a well is paramount for most réservoir calculations. In a horizontal well or a multi-lateralwell, the H of the well bore penetrating the réservoir isknown from electric logging methods, and more recently bylogging while drilling techniques. However, the logged 25 réservoir interval may not be the same as the H actually contributing to the well production and, in fact, the Hmay change with time.
The industry has adopted a laze faire attituderelating to the assumption of inflow performance in 30 horizontal and multi-lateral wells. Grand assumptions regarding inflow well performance are made based on 011483 2 surface data (i.e. flow rates, pressures, water eut,etc.), possible down hole pressure gauges, and rules ofthumb. The reality is that these assumption can lead topoor well performance, poor réservoir management, 5 completion equipment failures, and in the worst cases, catastrophic failure of the well.
The only method currently available to the réservoiror production engineer to monitor changes or losses in"H" is to run a wire line or tubing deployed production 10 log during well interventions. These logs are difficult to interpret, particularly in horizontal and high anglewells. This is due to the flow meters inability tomeasure the 3 phase flow rates, often referred in theliterature as water hold up or gas blow by. This 15 procedure of production logging and those known from
European patent applications Nos. 0442188 and 0508894require a rig mobilization, resulting in lost productionduring the rig up and rig down of the logging equipment,and présents a risk of loosing equipment in the well. 20 Production logging is not always possible (e.g. some subsea complétions or wells in which an electricalsubmersible pump (ESP) is installed). Moreover, since theproduction logging data is subject to interprétation, thedecision to run the production-logging suite is often 25 avoided. The end resuit is that the production is maintained by increasing the choke size at the surface.This can resuit in more damage, and ultimately in screenand well bore failures or large hydrate production andblowouts. 30 The method according to the preamble of claim 1 is known from European patent application 0442188. In theknown method a doppler flowmeter is temporarily loweredinto a wellbore on a wireline. Another logging probewhich.is equipped with fibre optical signal génération 011 483 3 and détection means is known from European patentapplication No. 0508894.
Summary of the Invention
The method of the invention is characterized in that5 a source and sensor are mounted permanently within a subterranean wellbore and/or surrounding formation.Detailed Description
The method of the invention provides a means formonitoring the flow of fluid, wherein fluid means liquids 10 or gases or mixtures of liquids and gases, from subterranean formations. Measurement takes placedirectly in the région where a measurement is desired.
In the case of a flowing well, the measurements may betaken while the well is producing. Thermal and/or 15 acoustic sources are placed in the fluid flow path and sensors capable of detecting température or acoustic 011483 4 changes placed near the sources detect changes to thefluid caused by the sources.
One embodiment of the invention provides a method formonitoring fluid flow within a région to be measured of a 5 subterranean formation. At least one source is placed within the formation. Placement is relatively permanent,meaning the source is set and then left in the measurement zone. At least one sensor is also placedwithin the région to be measured. Each sensor should be 10 adjacent to one or more sources, in close enough proximity to measure changes to the fluid caused by thesource (s). It is necessary to also provide at least onemeans for transmitting data from the sensors to at leastone data collection device. The data collection device 15 may be subterranean, on the surface, or in the air but it must be capable of communicating with an operator. Asused herein, an operator may be an object, such as anoperating station, or a human.
The sources may be optical sources, electrical heat 20 sources, acoustic sources, or combinations thereof.
Examples include thermisters, optical heaters, continuaiheating éléments, electric cables, sonar generators, andvibration generators. Because it is optimum to limitrestrictions in the formation, the preferred sensors are 25 optical fibres, which are small enough to be non- intrusive. The optical fibres may also act as the datatransmission means, thereby serving two purposes. Thesources and the sensors are preferably orientedperpendicular to the fluid flow. 30 When the subterranean formation is a well, the fluid flow région to be measured is typically within the wellbore, be it vertical, horizontal or deviated. A meansfor deploying the sensors and data links in a fairly non-intrusive manner is via hollow tubular members. 011483 - 5 -
The System of the invention is expected to performwell using applied well technology known as Micro OpticalSensing Technology ("MOST"). MOST allows for the miniaturization of sensing equipment in submersible5 equipment. Fundamentally, oil and gas well environments hâve restricted geometry and hostile conditions oftempérature and pressure. MOST is able to function inthese environments due to it's ability to use very smalldiameter data links (optic fibres) and to use sensors 10 that can withstand températures above 200 °C.
Since the sources, sensors and data links arepermanently installed in the desired région of theformation, there is no need for well interventions, suchas production logging. The method can provide a 15 continuai inflow performance profile of the formation on a real time basis and multiple flow détection nodes alongthe formation can be monitored.
The use of thermal sources and sensors will be usedas an example. A sériés of electrically or optically 20 powered heat sources may be placed along a well bore axis parallel to a sériés of thermal sensors. The thermalsources may be in many forms, including but not limitedto single point heating éléments like thermisters,optical heaters, or a continuai heating element like 25 electric cable.
The heat sensors are preferably single or multipleoptic fibres. The fibres may be deployed into the wellin multiple means and in multiple geometry. An exampleof deployment which will protect the fibres from hydrogen 30 exposure is to arrange the température sensors and data links in small hollow members, such as tubes. The flowdétection system is formed by placing the optic fibres inthe flow stream before the heaters, after the heaters, orboth. Other embodiments uses the optic fibres and 35 heaters deployed parallel to one another, surrounding one 6 01 1483 another in coil configurations, and many othergeometry's. The preferred embodiment places the heatsource and thermal sensors perpendicular to the fluidflowing in the well bore, such that the heat source heats 5 the fluid while the thermal sensors measure the heat change in the fluid stream flowing over the heat source.This System then forms a sériés of classic thermal flowmeters according to the following simplified heat flowéquation: 10 Q = Wcp (T2 - Τχ) where Q = heat transferred (BTU/Hr); W = mass flow rate of fluid (lbm/Hr); andCp = spécifie heat of fluid (BTü/lbm °F). 15 The accuracy of the flow meter is dépendent on the accuracy of spécifie heat data for the flowing fluids.
The spécifie heat of the fluids in the well will changewith time, flowing pressures, and réservoir conditions(e.g. coning). 20 Optimum well production requires the heat sources and température measurement devices to be small and non-intrusive to the well bore inside diameter. Non-intrusive deployment allows for the well to be fullyopened and thus allows for stimulation, squeeze, or 25 logging techniques to be performed through the completion with the sources, sensors and data links permanentlyinstalled.
The preferred sensors and/or data links of theinvention are optic fibres. Optic fibres are exotic 30 glass fibres which are available with many different coatings and by various different manufacturing methodsthat affect their optical characteristics. Optic fibreshâve a rapid decrease in functionality when exposed tohydrogen, and of course subterranean water is a readily 35 available hydrogen carrier. Therefore the fibres must be 011483 7 placed in a carrier. But other characteristics of opticfibres allow one fibre to read multiple changes along thefibre's length, an obvious advantage.
Fibers may be used in oil and gas wells in5 conjunction with Optical Time Delay Reflectometry ("OTDR") devices (commonly referred to as "intrinsicmeasurement"). Intrinsic sensing along the fibre is donewith application of quantum electrodynamics ("QED"). QEDrelates to the science of sub-atomic particles like 10 photons, électrons, etc. For this application, interest is in the photons travelling through a very spécial glasssub-atomic matrix. The probability, or probabilityamplitude, of the photon interacting with a Silicondioxide sub atomic structure is known for each 15 specialized optic fibre. The resulting back scattering of light as a function of thermal affects in the glasssubatomic structure has a very well known relationship tothe index of refraction of the optic fibre. Knowledge ofthe power and frequency of the light being pumped, or 20 launched down the optic fibre allows for calculation of the predicted light and frequency emitted or backscattered at a given length along the optic fibre.
The process of the invention uses OTDR and thermaland/or acoustic sources to measure flow in wells. Flow 25 changes at each node may be monitored versus time, providing a qualitative measurement on a permanent basisin real time. Knowing the glass and laser light beingused, a back scattering returning power can be measuredwith "OTDR" according to the following équation: 30 pbs(l) = PgAtVgCsNA^exp (f-2adx) where
Pbs = backscattering power returning from distance 1;Pq = launch power;
At = source time puise width, in time units; 011483 8
Vg = group velocity;
Cs = scattering constant; NA = numerical aperture of fibre; anda = total loss of atténuation coefficient. 5 OTDR can successfully and very repeatable measure the back scattering changes as a function of températurecaused by a laser pulsed light wave down an optic fibre,by relating Cs to and a.
Cs = (ctr) co + (ets) co + Pc/Pt (as)d 10 and α = ®co PC/pt (ad) where ar = Raman scattering coefficient;as = Rayleigh scattering coefficient; 15 ( )co ~ parameter associated with fibre core; ( )cl = parameter associated with fibre cladding; andpcl/ptotal = ratio of total power exists in cladding due to evanescent wave effects.
The OTDR equipment uses a laser source, an optic 20 fibre; a directional coupler connected to the fibre, an optoelectronic receiver, signal processing, and dataacquisition equipment.
The method of the invention allows simple actions tobe performed downhole without surface intervention, and 25 allows réservoir performance downhole to be monitored using 4D seismic and other technologies. The présentinvention may also be applied to other flow processes(i.e. pipelines, refining processes, etc.).
Claims (6)
1. A method for monitoring fluid flow within asubterranean région to be measured, said methodcomprising: placing at least one source within said subterranean5 région; placing at least one sensor within said région to bemeasured, wherein each said at least one sensor isadjacent to at least one source such that said sensormeasures changes to said fluid caused by said source; 1Ό providing at least one means for transmitting data from each said at least one sensor to at least one datacollection device, said at least one data collectiondevice capable of communicating with an operator,characterized in that the source and sensor are mounted 15 permanently within a subterranean wellbore and/or surrounding formation.
2. A method aecording to claim 1 wherein said source isselected from an optical source, an electrical heatsource, an acoustic source, and combinations thereof. 20
3. A method aecording to claim 2 wherein said source is selected from a thermister, an optical heater, acontinuai heating element, an electric cable, a sonargenerator, a vibration generator, and combinationsthereof. 25
4. A method aecording to claim 1 wherein said sensor is one or more optical fibres.
5. A method aecording to claim 1 wherein said one ormore sensor and said one or more source are orientedperpendicular to said fluid flow. 30
6. A method aecording to claim 4 wherein said sensors and data links are deployed in hollow tubular members.
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US7702398P | 1998-03-06 | 1998-03-06 |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| OA11483A true OA11483A (en) | 2004-05-03 |
Family
ID=22135652
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| OA1200000241A OA11483A (en) | 1998-03-06 | 2000-09-05 | Inflow detection apparatus and system for its use. |
Country Status (13)
| Country | Link |
|---|---|
| EP (1) | EP1060327B1 (en) |
| CN (1) | CN1289788C (en) |
| AU (1) | AU747413B2 (en) |
| BR (1) | BR9908571A (en) |
| CA (1) | CA2321539C (en) |
| DE (1) | DE69914462T2 (en) |
| DK (1) | DK1060327T3 (en) |
| EA (1) | EA004757B1 (en) |
| ID (1) | ID25807A (en) |
| NO (1) | NO317705B1 (en) |
| NZ (1) | NZ506369A (en) |
| OA (1) | OA11483A (en) |
| WO (1) | WO1999045235A1 (en) |
Families Citing this family (17)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US6720493B1 (en) | 1994-04-01 | 2004-04-13 | Space Electronics, Inc. | Radiation shielding of integrated circuits and multi-chip modules in ceramic and metal packages |
| WO2000011317A1 (en) * | 1998-08-25 | 2000-03-02 | Baker Hughes Incorporated | Method of using a heater with a fiber optic string in a wellbore |
| US6769805B2 (en) | 1998-08-25 | 2004-08-03 | Sensor Highway Limited | Method of using a heater with a fiber optic string in a wellbore |
| US6789621B2 (en) | 2000-08-03 | 2004-09-14 | Schlumberger Technology Corporation | Intelligent well system and method |
| US6799637B2 (en) | 2000-10-20 | 2004-10-05 | Schlumberger Technology Corporation | Expandable tubing and method |
| US7222676B2 (en) | 2000-12-07 | 2007-05-29 | Schlumberger Technology Corporation | Well communication system |
| CN100400495C (en) | 2003-04-09 | 2008-07-09 | 国际壳牌研究有限公司 | Process for the preparation of alkanediol |
| US20040252748A1 (en) | 2003-06-13 | 2004-12-16 | Gleitman Daniel D. | Fiber optic sensing systems and methods |
| AU2004309117B2 (en) * | 2003-12-24 | 2007-09-13 | Shell Internationale Research Maatschappij B.V. | Downhole flow measurement in a well |
| AU2004309118B2 (en) * | 2003-12-24 | 2008-06-12 | Shell Internationale Research Maatschappij B.V. | Method of determining a fluid inflow profile of wellbore |
| US7464588B2 (en) * | 2005-10-14 | 2008-12-16 | Baker Hughes Incorporated | Apparatus and method for detecting fluid entering a wellbore |
| US8355873B2 (en) | 2005-11-29 | 2013-01-15 | Halliburton Energy Services, Inc. | Method of reservoir characterization and delineation based on observations of displacements at the earth's surface |
| RU2353767C2 (en) * | 2006-02-17 | 2009-04-27 | Шлюмберже Текнолоджи Б.В. | Method of assessment of permeability profile of oil bed |
| DE102008056089A1 (en) * | 2008-11-06 | 2010-07-08 | Siemens Aktiengesellschaft | Method for measuring state variable e.g. temperature, of oil pipeline in offshore-area of oil and gas pumping station, involves using electrically operated measuring devices, and diverging supply energy from electricity provided to pipeline |
| US9167630B2 (en) * | 2011-10-17 | 2015-10-20 | David E. Seitz | Tankless water heater |
| US9151152B2 (en) | 2012-06-20 | 2015-10-06 | Schlumberger Technology Corporation | Thermal optical fluid composition detection |
| US11199086B2 (en) | 2016-09-02 | 2021-12-14 | Halliburton Energy Services, Inc. | Detecting changes in an environmental condition along a wellbore |
Family Cites Families (6)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US4905203A (en) * | 1988-09-30 | 1990-02-27 | Texaco Inc. | Downhole doppler flowmeter |
| US4982383A (en) * | 1988-09-30 | 1991-01-01 | Texaco Inc. | Downhole ultrasonic transit-time flowmetering means and method |
| FR2675202A1 (en) * | 1991-04-11 | 1992-10-16 | Schlumberger Services Petrol | METHOD FOR LOCALLY DETERMINING THE NATURE OF A PHASE IN A MOVING THREE-PHASE FLUID AND APPLICATION OF THIS METHOD TO DETERMINING FLOW FLOW PARAMETERS. |
| US5208650A (en) * | 1991-09-30 | 1993-05-04 | The United States Of America As Represented By The Secretary Of The Navy | Thermal dilation fiber optical flow sensor |
| DE69428496T2 (en) * | 1993-05-21 | 2002-05-23 | Dhv International, Inc. | DRILL HOLE INSTRUMENT CABLE WITH REDUCED DIAMETER |
| FR2707697A1 (en) * | 1993-06-30 | 1995-01-20 | Fis | Well wall productivity imaging probe |
-
1999
- 1999-03-04 WO PCT/EP1999/001397 patent/WO1999045235A1/en active IP Right Grant
- 1999-03-04 CA CA002321539A patent/CA2321539C/en not_active Expired - Fee Related
- 1999-03-04 CN CNB998037389A patent/CN1289788C/en not_active Expired - Fee Related
- 1999-03-04 EP EP99911735A patent/EP1060327B1/en not_active Expired - Lifetime
- 1999-03-04 NZ NZ506369A patent/NZ506369A/en unknown
- 1999-03-04 DE DE69914462T patent/DE69914462T2/en not_active Expired - Fee Related
- 1999-03-04 BR BR9908571-2A patent/BR9908571A/en not_active IP Right Cessation
- 1999-03-04 ID IDW20001689A patent/ID25807A/en unknown
- 1999-03-04 AU AU30314/99A patent/AU747413B2/en not_active Ceased
- 1999-03-04 DK DK99911735T patent/DK1060327T3/en active
- 1999-03-04 EA EA200000907A patent/EA004757B1/en not_active IP Right Cessation
-
2000
- 2000-09-05 OA OA1200000241A patent/OA11483A/en unknown
- 2000-09-05 NO NO20004434A patent/NO317705B1/en unknown
Also Published As
| Publication number | Publication date |
|---|---|
| EP1060327B1 (en) | 2004-01-28 |
| ID25807A (en) | 2000-11-09 |
| EA200000907A1 (en) | 2001-04-23 |
| EA004757B1 (en) | 2004-08-26 |
| NO20004434D0 (en) | 2000-09-05 |
| NZ506369A (en) | 2003-01-31 |
| DE69914462D1 (en) | 2004-03-04 |
| EP1060327A1 (en) | 2000-12-20 |
| WO1999045235A1 (en) | 1999-09-10 |
| NO20004434L (en) | 2000-09-05 |
| NO317705B1 (en) | 2004-12-06 |
| BR9908571A (en) | 2000-11-21 |
| AU3031499A (en) | 1999-09-20 |
| DK1060327T3 (en) | 2004-03-15 |
| CN1289788C (en) | 2006-12-13 |
| DE69914462T2 (en) | 2004-07-01 |
| AU747413B2 (en) | 2002-05-16 |
| CA2321539C (en) | 2008-02-12 |
| CN1292844A (en) | 2001-04-25 |
| CA2321539A1 (en) | 1999-09-10 |
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