CN1292844A - Inflow detection apparatus and system for its use - Google Patents
Inflow detection apparatus and system for its use Download PDFInfo
- Publication number
- CN1292844A CN1292844A CN998037389A CN99803738A CN1292844A CN 1292844 A CN1292844 A CN 1292844A CN 998037389 A CN998037389 A CN 998037389A CN 99803738 A CN99803738 A CN 99803738A CN 1292844 A CN1292844 A CN 1292844A
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- well
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Links
- 238000001514 detection method Methods 0.000 title description 2
- 238000000034 method Methods 0.000 claims abstract description 34
- 239000012530 fluid Substances 0.000 claims abstract description 27
- 238000012544 monitoring process Methods 0.000 claims abstract description 8
- 239000013307 optical fiber Substances 0.000 claims description 15
- 238000005259 measurement Methods 0.000 claims description 10
- 238000010438 heat treatment Methods 0.000 claims description 9
- 230000015572 biosynthetic process Effects 0.000 abstract description 3
- 238000013480 data collection Methods 0.000 abstract 2
- 239000000835 fiber Substances 0.000 description 13
- 238000004519 manufacturing process Methods 0.000 description 11
- 230000008859 change Effects 0.000 description 6
- 238000000253 optical time-domain reflectometry Methods 0.000 description 5
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 5
- 238000005553 drilling Methods 0.000 description 4
- 238000005516 engineering process Methods 0.000 description 4
- 239000007789 gas Substances 0.000 description 4
- 239000011521 glass Substances 0.000 description 3
- 239000001257 hydrogen Substances 0.000 description 3
- 229910052739 hydrogen Inorganic materials 0.000 description 3
- 239000007788 liquid Substances 0.000 description 3
- 230000008569 process Effects 0.000 description 3
- UFHFLCQGNIYNRP-UHFFFAOYSA-N Hydrogen Chemical compound [H][H] UFHFLCQGNIYNRP-UHFFFAOYSA-N 0.000 description 2
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 2
- 239000002343 natural gas well Substances 0.000 description 2
- 239000003129 oil well Substances 0.000 description 2
- 239000003208 petroleum Substances 0.000 description 2
- 238000001069 Raman spectroscopy Methods 0.000 description 1
- 238000004458 analytical method Methods 0.000 description 1
- 230000008901 benefit Effects 0.000 description 1
- 238000009529 body temperature measurement Methods 0.000 description 1
- 238000005253 cladding Methods 0.000 description 1
- 239000011248 coating agent Substances 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
- 230000009189 diving Effects 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 230000005611 electricity Effects 0.000 description 1
- 230000005520 electrodynamics Effects 0.000 description 1
- 230000005284 excitation Effects 0.000 description 1
- 239000003365 glass fiber Substances 0.000 description 1
- 150000002431 hydrogen Chemical class 0.000 description 1
- 230000004941 influx Effects 0.000 description 1
- 238000009434 installation Methods 0.000 description 1
- 230000003993 interaction Effects 0.000 description 1
- 239000011159 matrix material Substances 0.000 description 1
- 239000000203 mixture Substances 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 238000012806 monitoring device Methods 0.000 description 1
- 230000003287 optical effect Effects 0.000 description 1
- 230000005693 optoelectronics Effects 0.000 description 1
- 239000002245 particle Substances 0.000 description 1
- 230000035699 permeability Effects 0.000 description 1
- 238000011084 recovery Methods 0.000 description 1
- 238000007670 refining Methods 0.000 description 1
- 239000000523 sample Substances 0.000 description 1
- 239000000377 silicon dioxide Substances 0.000 description 1
- 238000012360 testing method Methods 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)
- Examining Or Testing Airtightness (AREA)
- Nozzles (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
The present invention relates to a kind of method that fluid flows in the stratum of measuring; The particularly measurement of the flow rate of the liquid in the stratum, gas and fluid-mixing.
New challenge to completion and petroleum production engineering standard has appearred in the latest development along with the oil drilling industry of for example horizontal well of wellbore construction technology and polygon well.The horizontal well of high load capacity under deep water conditions also promotes the perfect of technical tool that the Petroleum Engineer uses, to be used for safety and exploit oil-producing formation modestly.
Permeability (" K ") and height (" H ") that the typical method of reservoir monitoring is suitable for well exploitation area are known.Should " KH " often periodically determine, and be commonly referred to be constant by production logging.Concerning calculated most of reservoirs, " KH " of well was primary.In horizontal well or polygon well, the H that penetrates the pit shaft of reservoir is learnt by electrical logging, and is learnt by the technology of drilling well simultaneous logging recently.But the reservoir interval that has write down may promote that the H of well exploitation is different with reality, but and H time to time change in fact.
Industrial hypothesis to the inflow characteristic in horizontal well and the polygon well has been taked passive (lazefaire) attitude.The main hypothesis relevant with the influx well performance is based on surface data (being flow rate, pressure, water content etc.), possible pressure bomb and empirical rule.The fact is that these hypothesis can cause bad well performance, bad reservoir management, the damage of completion equipment and the calamity breaking-up of well in the worst case.
The variation of the only obtainable at present monitoring of oil production engineer or production engineer " H " and the method for loss are to move the production logging of wire rope or configuring pipes between the well intervention period.These well loggings particularly are difficult to explain under the situation of level and high angle hole.This is because flow meter energy measurement 3 phase flow rates not, thinks in the literature that usually water resistance (water hold up) the gentle body drain that stagnates goes out (gas blow by).This method of production logging needs rig to move, and this can cause exploitation losses in the upper and lower process of the rig of logging equipment, and the danger that equipment gets loose in the well occurred.Production logging is not always possible (for example, some subsea-completed wells or well are wherein installed electric submersible pump (ESP)).And, because the production logging data through interpretive analysis, determine not move the production logging group thus through regular meeting.Last result keeps exploitation by increase restriction size in the surface.This may cause bigger danger, and finally causes sieve plate and borehole failure, or big moisture hydrate exploitation, and bleed or steam.
Method of the present invention provides the device that directly test fluid flows in the tested zone on stratum, and described method comprises:
In described stratum, place at least one source;
Place at least one sensor in described tested zone, wherein each described at least one sensor is near at least one source, and described like this sensor measurement is caused the variation of described fluid by described source;
Provide at least one to be used for data are passed to the device of at least one transacter from each described at least one sensor, described at least one transacter can be communicated with an operator.
A kind of method also is provided, and the fluid that this method is used for when well bore is online in the tested zone of monitoring pit shaft flows, and described method comprises:
Place at least one source in described tested zone, this source is selected from thermal source, sound source and its combination;
In described tested zone, place at least one sensor, this sensor is elected from heat sensor, sonic transducer and its combination, wherein each described at least one sensor is near at least one source, the change of the described fluid that described like this sensor measurement is caused by described source;
Provide at least one to be used for data are sent to the device of at least one transacter from each described at least one sensor, described at least one transacter can communicate with the operator.
Method of the present invention provides monitoring a kind of measure that fluid flows, and wherein fluid refers to the liquid in the stratum or the mixture of gas or liquid and gas.Measure directly and in the zone that hope is measured, carry out.Under the situation of flowing well, in recovery well, measure.Heat and/or sound source are placed on the fluid flow path, can detected temperatures or the sensor of the variation of sound place the change of fluid that causes with detection resources near the source.
One embodiment of the present of invention provide a kind of method, and the fluid that this method is used for detecting in the tested zone on stratum flows.At least one source is placed in the stratum.Placement is quite permanent, and the source that this means is stayed then and measured the area through setting.At least one sensor also is placed in the tested zone.Each sensor should be near one or more sources, and this sensor close enough source is so that the change of fluid that the measurement source causes.Also must provide at least one device, be used for data are sent at least one transacter from sensor.Transacter can be underground, and from the teeth outwards, perhaps in air, but it must be got in touch with the operator.As employed here, an operator can be an object, for example active station or people.
The source can be light source, electric heat source, sound source or its combination.Example comprises thermistor, light heater, continuous heating element, cable, sonar generator and vibration machine.Because the limitation on its optimum restriction stratum, preferred sensor is an optical fiber, and these optical fibers are little of not producing interference.Optical fiber also can be used as data link, therefore as two purposes.Source and sensor are preferably perpendicular to fluid stream location.
When the stratum was well, tested fluid flow region territory was typically in pit shaft, and this pit shaft is vertical, level or inclination.Sensors configured and with the device of the data link of the mode quite do not disturbed through blank pipe shape parts.
Wish that system of the present invention uses the application drilling technology that is known as low-light sensing technology (" MOST ") to finish drilling well.MOST allows the miniaturization of the sensing equipment in diving apparatus.Fundamentally, the oil and natural gas well environment has the geometrical condition and the hostile condition of limited temperature and pressure.MOST can be used in these environment, and this is to surpass 200 ℃ temperature because it can use the unusual data link of minor diameter (optical fiber) and use sensor to bear.
Because source, sensor and data link for good and all are installed in the desired area on stratum, do not need the well intervention, for example production logging.The shaft bottom that this method can be provided at the stratum on the real-time basis flows into dynamic outline, and can monitor the multistage stream probe node along the stratum.
The use of thermal source and sensor will be as an example.The thermal source of a series of electricity or luminous energy can be parallel to a series of heat sensors along the well bore axis arranged.Thermal source can be a various ways, includes but are not limited to for example electro-hot regulator, light heating element or continuous heater element cable for example of single-point heater element.
The preferably single or many optical fibers of heat sensor.These fibers can be placed in the well of multiple device and multiple geometry.The protection fiber is for example arranged temperature pick up and data link in the pipe so that make its profile instance that is not exposed in the hydrogen be at little hollow member.By before heating element, behind the heating element or under these two situations, optical fiber is placed in the stream that flows, form the mobile monitoring system.Other embodiment uses the placement that is parallel to each other, and structure centers on mutually and the optical fiber and the heating element of many other geometries to coil.Preferred embodiment is arranged thermal source and heat sensor perpendicular to fluid flow direction in well bore, thermal source has heated fluid like this, flows through the thermal change of the fluid stream of thermal source when the heat sensor measurement.Then, according to the hot-fluid formula of simplifying below, this system has formed the heat flowmeter of a series of classics:
Q=W
Cp(T
2-T
1)
Wherein:
The heat (BTU/Hr) that Q=transmits;
The mass flowrate of W=fluid (1bm/Hr); With
The specific heat of Cp=fluid (BTU/1bm).
The precision of flow meter depends on the precision of the ratio dsc data of streaming flow.The specific heat of the fluid in the well in time, flowing pressure and reservoir condition (for example taper) and change.
Suitable well exploitation needs thermal source and temperature measurement equipment little, and can not invade the internal diameter inboard of well bore.Do not have the layout of invading and allow well to open fully, allow to be provided with the source of permanent installation like this, the completion of sensor and data link adopts excitation, squeezing or logging technique.
Preferred sensor of the present invention and/or data link are optical fibers.Optical fiber is rare glass fiber, and the various production method by many different coating and the optical characteristics by influencing them obtains this fiber.In the time of in being exposed to hydrogen, the optical fiber function reduces fast, and underground water is the hydrogen carrier that easily obtains certainly.Therefore, fiber must be placed in the carrier.But fiber of fibre-optic another characteristic permission reads the multiple variation along fibre length, a tangible advantage.
Fiber can be used in the oil and natural gas well, and is used in combination optics time delay reflectometer (" OTDR ") device (so-called " the inherent measurement ").Inherent sensing along fiber has utilized quantrm electrodynamics (" QED ").QED relates to for example photon of subatomic particle science, electronics etc.For this application, interest is the photon motion through the very special subatomic matrix of glass.For each particular light guide fiber, the possibility or the possibility amplitude of the photon of known and the subatomic structural interaction of silica.Final backscattering as the light of the function of the heat affecting in the subatomic structure of glass has and the known relation of fibre-optic refractive index.Draw or the energy and the frequency of the light of emission through optical fiber, allow to calculate and send or backscattered predetermined light and frequency at given length upper edge optical fiber.
Method of the present invention uses OTDR and heat and/or sound source with flowing in the measuring well.Can monitor flowing over time of each node, the observational measurement on the real-time permanent basis is provided.Known use glass and laser can be measured the energy that backscattering is returned with " OTDR " according to following formula: Pbs (1)=1/2 P
0Δ t V
gC
sNA
2Exp (∫-2 α dx)
Wherein
Pbs=is from the distance 1 backscattering energy that returns;
P
0=emitted energy;
Δ t=source time pulse width is a unit with time;
V
g=group velocity;
C
s=scattering constant;
The numerical aperture of NA=fiber; With
α=complete attenuation loss coefficient.
OTDR can be successfully and can repeatedly be measured backscattered variation as temperature funtion, and this changes the light wave by fibre-optic laser pulse, causes by relevant Cs and α.Cs≌(α
r)
C0+(α
s)
C0+Pc/Pt(α
s)
d
With
α=α
C0+P
c/P
t(α
d)
Wherein
α
r=Raman scattering coefficient;
α
s=rayleigh scattering coefficient;
()
C0=the parameter relevant with fibre core;
()
C1=the parameter relevant with cladding of fiber; With
P
Cl/ P
Total=in covering because the ratio of the whole energy that the evanescent wave effect produces.
The OTDR device uses lasing light emitter, optical fiber; The directional coupler, optoelectronic receiver, signal processor and the data acquisition unit that connect fiber.
Method of the present invention does not need surperficial intervention simply to implement in the down-hole, and allows to use 4D earthquake and other technical monitoring down-hole reservoir characteristic.The present invention also is used for other flow process (being pipeline, refining process etc.).Obviously, only otherwise exceed the spirit and scope of the invention that propose here, those of ordinary skill in the art also can carry out many changes and modification to the present invention.
Claims (11)
1. monitor the method that fluid flows for one kind in the tested zone on stratum, described method comprises:
In described stratum, place at least one source;
Place at least one sensor in described tested zone, wherein each described at least one sensor is near at least one source, the variation of the described fluid that described like this sensor measurement is caused by described source;
Provide at least one to be used for data are sent to the device of at least one transacter from each described at least one sensor, described at least one transacter can be got in touch with an operator.
2. the method for claim 1 is characterized in that the selection from light source, electric heat source, sound source and its combination of described source.
3. method as claimed in claim 2 is characterized in that the selection from thermistor, light heating element, continuous heating element, cable, sonar generator, vibration machine and its combination of described source.
4. the method for claim 1 is characterized in that described sensor is one or more optical fibers.
5. the method for claim 1 is characterized in that described one or more sensor and described one or more source locate perpendicular to described direction of flow.
6. method that the fluid that is used for monitoring in the tested zone of pit shaft flows, described method comprises:
Place at least one source in described tested zone, this source is selected from thermal source, sound source and its combination;
In described tested zone, place at least one sensor, this sensor is selected from heat sensor, sonic transducer and its combination, wherein each described at least one sensor is near at least one source, the variation of the described fluid that described like this sensor measurement is caused by described source;
Provide at least one to be used for data are sent to the device of at least one transacter from each described at least one sensor, described at least one transacter can be got in touch with the operator.
7. method as claimed in claim 6 is characterized in that the selection from light source, electric heat source, sound source and its combination of described source.
8. method as claimed in claim 7 is characterized in that the selection from thermistor, light heating element, continuous heating element, cable, sonar generator, vibration machine and its combination of described source.
9. method as claimed in claim 6 is characterized in that described sensor is one or more optical fibers.
10. method as claimed in claim 9 is characterized in that described sensor and data link are arranged in the hollow pipe fitting.
11. method as claimed in claim 6 is characterized in that in the described tested zone of described pit shaft, described one or more sensors and described one or more source are directed perpendicular to described fluid stream.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US7702398P | 1998-03-06 | 1998-03-06 | |
| US60/077,023 | 1998-03-06 |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CN1292844A true CN1292844A (en) | 2001-04-25 |
| CN1289788C CN1289788C (en) | 2006-12-13 |
Family
ID=22135652
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CNB998037389A Expired - Fee Related CN1289788C (en) | 1998-03-06 | 1999-03-04 | 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) |
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN101443531B (en) * | 2006-02-17 | 2013-09-18 | 普拉德研究及开发股份有限公司 | Method for determining filtration properties of rocks |
| CN108981137A (en) * | 2011-10-17 | 2018-12-11 | 戴维·E·塞兹 | Immediately heating water heater |
Families Citing this family (15)
| 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 |
| AU5791999A (en) * | 1998-08-25 | 2000-03-14 | 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 |
| WO2004089866A1 (en) | 2003-04-09 | 2004-10-21 | Shell Internationale Research Maatschappij B.V. | Process for the preparation of alkanediol |
| US20040252748A1 (en) | 2003-06-13 | 2004-12-16 | Gleitman Daniel D. | Fiber optic sensing systems and methods |
| BRPI0418100A (en) | 2003-12-24 | 2007-04-17 | Shell Int Research | methods for determining a fluid inflow profile over a permeable inflow region of an underground wellbore and producing crude oil from an underground formation, and a distributed heater and temperature sensing system |
| GB2426047B (en) * | 2003-12-24 | 2007-07-25 | Shell Int Research | Downhole flow measurement in a well |
| 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 |
| 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 |
| 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 |
| CA2140748C (en) * | 1993-05-21 | 1999-08-10 | Philip K. Schultz | Reduced diameter down-hole instrument cable |
| FR2707697A1 (en) * | 1993-06-30 | 1995-01-20 | Fis | Well wall productivity imaging probe |
-
1999
- 1999-03-04 AU AU30314/99A patent/AU747413B2/en not_active Ceased
- 1999-03-04 ID IDW20001689A patent/ID25807A/en unknown
- 1999-03-04 EP EP99911735A patent/EP1060327B1/en not_active Expired - Lifetime
- 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 DK DK99911735T patent/DK1060327T3/en active
- 1999-03-04 BR BR9908571-2A patent/BR9908571A/en not_active IP Right Cessation
- 1999-03-04 NZ NZ506369A patent/NZ506369A/en unknown
- 1999-03-04 CN CNB998037389A patent/CN1289788C/en not_active Expired - Fee Related
- 1999-03-04 DE DE69914462T patent/DE69914462T2/en not_active Expired - Fee Related
- 1999-03-04 EA EA200000907A patent/EA004757B1/en not_active IP Right Cessation
-
2000
- 2000-09-05 NO NO20004434A patent/NO317705B1/en unknown
- 2000-09-05 OA OA1200000241A patent/OA11483A/en unknown
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN101443531B (en) * | 2006-02-17 | 2013-09-18 | 普拉德研究及开发股份有限公司 | Method for determining filtration properties of rocks |
| CN108981137A (en) * | 2011-10-17 | 2018-12-11 | 戴维·E·塞兹 | Immediately heating water heater |
Also Published As
| Publication number | Publication date |
|---|---|
| CA2321539A1 (en) | 1999-09-10 |
| WO1999045235A1 (en) | 1999-09-10 |
| EA200000907A1 (en) | 2001-04-23 |
| EP1060327B1 (en) | 2004-01-28 |
| DK1060327T3 (en) | 2004-03-15 |
| CN1289788C (en) | 2006-12-13 |
| BR9908571A (en) | 2000-11-21 |
| NO317705B1 (en) | 2004-12-06 |
| EA004757B1 (en) | 2004-08-26 |
| OA11483A (en) | 2004-05-03 |
| NO20004434D0 (en) | 2000-09-05 |
| ID25807A (en) | 2000-11-09 |
| NO20004434L (en) | 2000-09-05 |
| NZ506369A (en) | 2003-01-31 |
| EP1060327A1 (en) | 2000-12-20 |
| DE69914462D1 (en) | 2004-03-04 |
| AU747413B2 (en) | 2002-05-16 |
| CA2321539C (en) | 2008-02-12 |
| AU3031499A (en) | 1999-09-20 |
| DE69914462T2 (en) | 2004-07-01 |
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