US20050173112A1 - Annulus plugging detection using a pressure transmitter in gas-lift oil production - Google Patents
Annulus plugging detection using a pressure transmitter in gas-lift oil production Download PDFInfo
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- US20050173112A1 US20050173112A1 US11/050,637 US5063705A US2005173112A1 US 20050173112 A1 US20050173112 A1 US 20050173112A1 US 5063705 A US5063705 A US 5063705A US 2005173112 A1 US2005173112 A1 US 2005173112A1
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- outer annulus
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Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
- E21B43/121—Lifting well fluids
- E21B43/122—Gas lift
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/06—Measuring temperature or pressure
Definitions
- the present invention is related to gas-lift oil production operations. More particularly, the present invention is related to improved annulus plugging detection in such operations.
- the gas-lift method of lifting crude oil is used in many of the world's oil wells. Indeed, in fields where significant quantities of associated gas are present and produced solids are involved, it is the preferred method of augmenting the natural reservoir pressure and thus increasing production.
- FIG. 1 is diagrammatic view of a typical gas-lift oil well.
- Central pipe 10 defines a passageway 12 through which crude oil flows in the direction of arrow 14 up to the ground and ultimately to one or more collection stations.
- the middle section includes middle conduit 16 disposed preferably, concentrically, about pipe 10 to define an inner annulus 17 between conduit 16 and pipe 10 .
- Pressurized gas is injected into inner annulus 17 and travels down, in the direction of arrow 18 , to the bottom of the piping.
- the pressurized gas then enters the middle section that contains the crude oil through a special section. This creates lift for the crude oil to ascend via pipe 10 to the surface.
- inner annulus 17 is highly pressurized and often has temperatures exceeding that of ambient.
- An outer shell 20 defines an outer annulus 22 between shell 20 and conduit 16 .
- Outer annulus 22 and shell 20 help protect the environment against leaks and any thermal impacts of the pumping operation.
- the pressure within outer annulus 22 is slightly below atmospheric pressure and would not have any materials, such as oil or gas, disposed therein.
- outer annulus 22 may become pressurized due to leaks from inner annulus 17 or cracks in conduit 16 defining the barrier between inner annulus 17 and outer annulus 22 .
- the pressure within outer annulus may sometimes reach levels on the order of 2000 pounds per square inch. In these cases, a special permit may be required from the state, or other suitable regulatory authority, to operate the well. In such situations, the pressure within outer annulus 22 must be monitored to comply with regulations.
- a pressure transmitter such as transmitter 24 is sometimes operably coupled to outer annulus 22 in order to monitor the pressure therein.
- the well temperature may be around 160° F., which is induced by the relatively high-pressure gas injection to the system. Due to various reasons, the well may stop operation occasionally. In this case, the well temperature close to ground and well head above ground will drop in temperature to that of ambient. In these cases, the material inside outer annulus 22 can freeze creating a plug in annulus 22 and/or instrument piping 26 . When this happens, pressure measurements taken using transmitter 24 will no longer reflect the actual pressures in outer annulus 22 . When the well starts to operate again, the temperature in the well starts to rise. This temperature rise will cause expansion of the material in the bottom sections of annulus 22 . Since there may be a frozen plug at the top section, significant increases in pressure in annulus 22 below the plug can occur.
- Outer annulus plugging detection is provided for gas-lift oil wells.
- the outer annulus detection is effected using a pressure transmitter.
- the pressure transmitter provides an indication of pressure within an outer annulus of the oil well.
- a parameter related to a plurality of outer annulus pressure readings is used to provide an indication of annulus plugging. Examples of the statistical parameter include mean and standard deviation.
- FIG. 1 is diagrammatic view of a typical gas-lift oil well.
- FIG. 2 is diagrammatic view of a pressure transmitter operably coupled to an outer annulus in accordance with an embodiment of the present invention.
- FIG. 3 shows results from a test performed in accordance with an embodiment of the present invention.
- FIG. 4 shows the standard deviation as a function of time for the same test cases as that of FIG. 3 .
- FIG. 2 is diagrammatic view of a pressure transmitter 100 operably coupled to outer annulus 22 .
- Pressure sensor 102 of transmitter 100 is fluidically coupled to annulus 22 and has an electrical characteristic that varies with the pressure in annulus 22 .
- Pressure sensor 102 can be a capacitive-type pressure sensor, a resistance-based strain gauge-type sensor, or any other suitable type of sensor.
- Pressure sensor 102 is electrically coupled to analog to digital converter 104 .
- Converter 104 converts an analog signal from sensor 102 into a digital value that it provides, via line 106 , to controller 108 . Additionally, in accordance with one embodiment of the invention, converter 104 may provide an auxiliary output 110 , illustrated in phantom, that simply reflects a digital bitstream indicative of the analog reading.
- a digital bitstream allows higher resolution, which is useful for some types of statistical processing.
- a traditional analog to digital converter may provide digital conversions on line 106 at approximately 22 times per second, the frequency of the digital bitstream on line 110 may be over 100 kHz.
- Power module 112 can include any suitable circuitry for receiving and conveying power to the components of transmitter 100 .
- Module 112 is coupled to all components requiring power as indicated at line 114 .
- Module 112 may include an energy storage cell, or may include suitable circuitry to couple to a source of energy. It is known for some process industry standard protocols to provide operating power. Examples of such protocols include HART, and FOUNDATIONTM Fieldbus.
- Power module 112 may also include one or more suitable transducers for converting potential energy into electrical energy for transmitter 100 .
- module 112 may include one or more solar cells, for example.
- Communications module 116 is coupled to controller 108 and allows transmitter 100 to communicate to one or more external devices.
- module 116 will be suitably adapted.
- Transmitter 100 can provide a first signal indicative of pressure within annulus 22 , and a second signal indicative of annulus plugging.
- Known protocols allow such signals to be provided over the same communication lines. For example, one signal could be provided in analog format, and the second signal could be a superimposed digital signal.
- Controller 108 is preferably a microprocessor. Controller 108 could be part of transmitter 100 , or may reside in a remote location from transmitter 100 . Controller 108 may include internal memory (not separately illustrated) and/or may be coupled to external memory 120 . Using internal memory, external memory 120 , or any combination thereof, controller 108 will store pressure measurement data related to readings from pressure sensor 102 over time. In accordance with embodiments of the present invention, it has been determined that secondary calculations based upon a plurality of temporally spaced readings related to pressure sensor 102 can reveal the plugging of annulus 22 . Much of the remainder of the description will focus upon the use of statistical parameters. However, embodiments of the present invention can be practiced using other analytical techniques such as fuzzy logic, neural networks, learning techniques, trend analysis, and any other suitable methods, or any combination thereof.
- FIG. 3 shows results from one of the test performed. This plot presents the mean parameter as a function of time.
- the normal operating pressure in outer annulus 22 is approximately 426 pounds per square inch. Every time that a valve was closed to simulate annulus plugging, the mean parameter pressure reading showed a significant drop in value compared to normal operating pressure. It has been concluded that the temperature changes and pipe/valve leaks contribute to this change as a result of plugging. Accordingly, pressure transmitter 100 can be characterized, or otherwise calibrated to a known non-plugged condition. Then, if the mean of the pressure sensor readings deviates beyond an allowable threshold from the baseline “good” condition, an alarm, or other suitable indication, is provided from pressure transmitter 100 indicating annulus plugging.
- FIG. 4 shows the standard deviation as a function of time for the same test cases of that of FIG. 3 .
- the standard deviation parameter presents a significantly more distinctive signature for plugging indications. Each time the system was plugged, a peak was observed in the standard deviation. As is apparent from the results illustrated in FIG. 4 , standard deviation may be used alone, or in combination with the mean to provide annulus plugging detection.
- pressure transmitter 100 is provided with a notification regarding pumping operations, either stopping, starting, or both. Thus, when pressure transmitter 100 receives a notification that pumping is starting again, it may wait a pre-selected duration before expecting measurements to be acceptable.
- embodiments of the present invention can be practiced by accessing the outer annulus pressure at selected intervals, or even in response to technician requests. However, sufficient numbers of pressure measurements must be taken by pressure sensor 102 in order to provide statistical computations.
Abstract
Outer annulus plugging detection is provided for gas-lift oil wells. The outer annulus detection is effected using a pressure transmitter. The pressure transmitter provides an indication of pressure within an outer annulus of the oil well. A statistical parameter related to a plurality of outer annulus pressure readings is used to provide an indication of annulus plugging. Examples of the statistical parameter include mean and standard deviation.
Description
- The present application is based on and claims the benefit of U.S. provisional patent application Ser. No. 60/542,185, filed Feb. 5, 2004, the content of which is hereby incorporated by reference in its entirety.
- The present invention is related to gas-lift oil production operations. More particularly, the present invention is related to improved annulus plugging detection in such operations.
- The gas-lift method of lifting crude oil is used in many of the world's oil wells. Indeed, in fields where significant quantities of associated gas are present and produced solids are involved, it is the preferred method of augmenting the natural reservoir pressure and thus increasing production.
- Because the technique involves comparatively compact equipment at the well head, it is especially attractive where space is at a premium, such as offshore, and where access for maintenance is restricted.
-
FIG. 1 is diagrammatic view of a typical gas-lift oil well.Central pipe 10 defines apassageway 12 through which crude oil flows in the direction ofarrow 14 up to the ground and ultimately to one or more collection stations. The middle section includesmiddle conduit 16 disposed preferably, concentrically, aboutpipe 10 to define aninner annulus 17 betweenconduit 16 andpipe 10. Pressurized gas is injected intoinner annulus 17 and travels down, in the direction ofarrow 18, to the bottom of the piping. The pressurized gas then enters the middle section that contains the crude oil through a special section. This creates lift for the crude oil to ascend viapipe 10 to the surface. By the nature of this process,inner annulus 17 is highly pressurized and often has temperatures exceeding that of ambient. Anouter shell 20 defines anouter annulus 22 betweenshell 20 andconduit 16.Outer annulus 22 andshell 20 help protect the environment against leaks and any thermal impacts of the pumping operation. In an ideal situation, the pressure withinouter annulus 22 is slightly below atmospheric pressure and would not have any materials, such as oil or gas, disposed therein. However, in actual operations,outer annulus 22 may become pressurized due to leaks frominner annulus 17 or cracks inconduit 16 defining the barrier betweeninner annulus 17 andouter annulus 22. The pressure within outer annulus may sometimes reach levels on the order of 2000 pounds per square inch. In these cases, a special permit may be required from the state, or other suitable regulatory authority, to operate the well. In such situations, the pressure withinouter annulus 22 must be monitored to comply with regulations. - One factor that complicates monitoring the pressure within
outer annulus 22 is material disposed withinannulus 22, which may become filled (partially or fully) with materials such as water, mud, oil from the surroundings or from the reservoir. The presence of these materials can create a significant problem for pressure measurement because they may freeze at relatively high temperatures due to the significant pressures involved. As illustrated inFIG. 1 , a pressure transmitter, such astransmitter 24 is sometimes operably coupled toouter annulus 22 in order to monitor the pressure therein. - During normal oil pumping operations, the well temperature may be around 160° F., which is induced by the relatively high-pressure gas injection to the system. Due to various reasons, the well may stop operation occasionally. In this case, the well temperature close to ground and well head above ground will drop in temperature to that of ambient. In these cases, the material inside
outer annulus 22 can freeze creating a plug inannulus 22 and/orinstrument piping 26. When this happens, pressure measurements taken usingtransmitter 24 will no longer reflect the actual pressures inouter annulus 22. When the well starts to operate again, the temperature in the well starts to rise. This temperature rise will cause expansion of the material in the bottom sections ofannulus 22. Since there may be a frozen plug at the top section, significant increases in pressure inannulus 22 below the plug can occur. Outer annulus pressures exceeding 4000 pounds per square inch have been observed during this process. Due to the frozen plug at the top ofannulus 22, pressure measured usingtransmitter 24 will not indicate this severe pressure rise. Therefore, routine pressure monitoring at the well head may not help detect the issue. If the pressure in the well rises too much, it may cause an explosion at the top with leakage to the environment and potentially serious injury or even death. - Accordingly, it is extremely important to determine whether the outer annulus is becoming, or has become plugged. Further, in order to ensure that additional costs are not required in this monitoring process, it would be beneficial if such monitoring could be done without adding significant hardware, or technician time.
- Outer annulus plugging detection is provided for gas-lift oil wells. The outer annulus detection is effected using a pressure transmitter. The pressure transmitter provides an indication of pressure within an outer annulus of the oil well. A parameter related to a plurality of outer annulus pressure readings is used to provide an indication of annulus plugging. Examples of the statistical parameter include mean and standard deviation.
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FIG. 1 is diagrammatic view of a typical gas-lift oil well. -
FIG. 2 is diagrammatic view of a pressure transmitter operably coupled to an outer annulus in accordance with an embodiment of the present invention. -
FIG. 3 shows results from a test performed in accordance with an embodiment of the present invention. -
FIG. 4 shows the standard deviation as a function of time for the same test cases as that ofFIG. 3 . -
FIG. 2 is diagrammatic view of apressure transmitter 100 operably coupled toouter annulus 22.Pressure sensor 102 oftransmitter 100 is fluidically coupled toannulus 22 and has an electrical characteristic that varies with the pressure inannulus 22.Pressure sensor 102 can be a capacitive-type pressure sensor, a resistance-based strain gauge-type sensor, or any other suitable type of sensor.Pressure sensor 102 is electrically coupled to analog todigital converter 104. Converter 104 converts an analog signal fromsensor 102 into a digital value that it provides, vialine 106, to controller 108. Additionally, in accordance with one embodiment of the invention,converter 104 may provide anauxiliary output 110, illustrated in phantom, that simply reflects a digital bitstream indicative of the analog reading. The use of a digital bitstream allows higher resolution, which is useful for some types of statistical processing. For example, while a traditional analog to digital converter may provide digital conversions online 106 at approximately 22 times per second, the frequency of the digital bitstream online 110 may be over 100 kHz. -
Power module 112 can include any suitable circuitry for receiving and conveying power to the components oftransmitter 100.Module 112 is coupled to all components requiring power as indicated atline 114.Module 112 may include an energy storage cell, or may include suitable circuitry to couple to a source of energy. It is known for some process industry standard protocols to provide operating power. Examples of such protocols include HART, and FOUNDATION™ Fieldbus. Powermodule 112 may also include one or more suitable transducers for converting potential energy into electrical energy fortransmitter 100. Thus,module 112 may include one or more solar cells, for example. -
Communications module 116 is coupled tocontroller 108 and allowstransmitter 100 to communicate to one or more external devices. In embodiments wheretransmitter 100 is expected to communicate using an industry standard process communication protocol,module 116 will be suitably adapted. For example, iftransmitter 100 is to communicate using the FOUNDATION™ fieldbus protocol,module 116 may include any suitable known fieldbus communications circuitry.Transmitter 100, in some embodiments, can provide a first signal indicative of pressure withinannulus 22, and a second signal indicative of annulus plugging. Known protocols allow such signals to be provided over the same communication lines. For example, one signal could be provided in analog format, and the second signal could be a superimposed digital signal. -
Controller 108 is preferably a microprocessor.Controller 108 could be part oftransmitter 100, or may reside in a remote location fromtransmitter 100.Controller 108 may include internal memory (not separately illustrated) and/or may be coupled toexternal memory 120. Using internal memory,external memory 120, or any combination thereof,controller 108 will store pressure measurement data related to readings frompressure sensor 102 over time. In accordance with embodiments of the present invention, it has been determined that secondary calculations based upon a plurality of temporally spaced readings related topressure sensor 102 can reveal the plugging ofannulus 22. Much of the remainder of the description will focus upon the use of statistical parameters. However, embodiments of the present invention can be practiced using other analytical techniques such as fuzzy logic, neural networks, learning techniques, trend analysis, and any other suitable methods, or any combination thereof. - In order to understand the effects of plugging, various simulations were performed both on real oil wells and on simulated laboratory rigs. In these simulations, various valves on instrument piping were used to artificially induce a plugged annulus condition by isolating the measurement device from the process. A commercially available pressure transmitter sold under the trade designation 3051 S T, available from Rosemount, Inc., of Eden Prairie, Minn., was used as the pressure-measuring device. This transmitter was equipped with an
auxiliary data channel 110 for providing fast updating diagnostics for statistical calculations. The two statistical calculations used in the simulations were mean and standard deviation of the pressure measurement. However, embodiments of the present invention should not be considered to be limited to such statistical calculations. -
FIG. 3 shows results from one of the test performed. This plot presents the mean parameter as a function of time. In this particular case, the normal operating pressure inouter annulus 22 is approximately 426 pounds per square inch. Every time that a valve was closed to simulate annulus plugging, the mean parameter pressure reading showed a significant drop in value compared to normal operating pressure. It has been concluded that the temperature changes and pipe/valve leaks contribute to this change as a result of plugging. Accordingly,pressure transmitter 100 can be characterized, or otherwise calibrated to a known non-plugged condition. Then, if the mean of the pressure sensor readings deviates beyond an allowable threshold from the baseline “good” condition, an alarm, or other suitable indication, is provided frompressure transmitter 100 indicating annulus plugging. -
FIG. 4 shows the standard deviation as a function of time for the same test cases of that ofFIG. 3 . The standard deviation parameter presents a significantly more distinctive signature for plugging indications. Each time the system was plugged, a peak was observed in the standard deviation. As is apparent from the results illustrated inFIG. 4 , standard deviation may be used alone, or in combination with the mean to provide annulus plugging detection. - Another challenging situation for annulus plugging detection is when a well is stopped and started. In this case, the pressures in
outer annulus 22 will not be as high as during normal operation. However, statistical process monitoring may still be used in this case. If training has been performed on the pressure transmitter before the pumping operation is shut down, then the outer annulus mean pressure and its standard deviation can be recorded as baseline. When the well is started again, it is expected that the pressure measurements are expected to rise from its shutdown levels if there is no plugging. If there is plugging, the pressure measurements will not significantly rise, thus indicating plugged annulus. Thus, in accordance with one embodiment of the present invention,pressure transmitter 100 is provided with a notification regarding pumping operations, either stopping, starting, or both. Thus, whenpressure transmitter 100 receives a notification that pumping is starting again, it may wait a pre-selected duration before expecting measurements to be acceptable. - While it is preferred that monitoring of a statistical parameter related to the outer annulus pressure be done continuously, embodiments of the present invention can be practiced by accessing the outer annulus pressure at selected intervals, or even in response to technician requests. However, sufficient numbers of pressure measurements must be taken by
pressure sensor 102 in order to provide statistical computations. - Although the present invention has been described with reference to preferred embodiments, workers skilled in the art will recognize that changes may be made in form and detail without departing from the spirit and scope of the invention.
Claims (18)
1. A system for detecting outer annulus plugging in a gas-lift oil well, the system comprising:
a pressure transmitter operably coupleable to the outer annulus of the gas-lift oil well, the pressure transmitter being adapted to provide a signal related to pressure within the outer annulus; and
a controller configured to receive the signal and obtain a plurality of pressure measurements relative to the outer annulus, which measurements are temporally spaced, the controller being configured to calculate a parameter indicative of annulus plugging based on the plurality of pressure measurements.
2. The system of claim 1 , wherein the controller is a component of the pressure transmitter.
3. The system of claim 1 , wherein the pressure transmitter is adapted to provide a first signal indicative of pressure within the outer annulus, and a second signal indicative of plugging.
4. The system of claim 3 , wherein the pressure transmitter communicates over a digital process communication loop.
5. The system of claim 1 , wherein the pressure transmitter is powered by a digital process communication loop.
6. The system of claim 1 , wherein the pressure transmitter further comprises an analog-to-digital converter providing digital conversions to the controller.
7. The system of claim 1 , wherein the pressure transmitter further comprises an analog-to-digital converter providing a high-speed bitstream to the controller.
8. The system of claim 1 , wherein the parameter is a statistical parameter.
9. The system of claim 8 , wherein the statistical parameter is mean.
10. The system of claim 8 , wherein the statistical parameter is standard deviation.
11. The system of claim 8 , wherein the statistical parameter is a combination of mean and standard deviation.
12. The system of claim 1 , wherein the parameter is calculated using fuzzy logic.
13. The system of claim 1 , wherein the parameter is calculated using a neural network.
14. A method of determining whether an outer annulus of a gas-lift oil well is at least partially plugged, the method comprising:
obtaining a plurality of temporally spaced pressure measurements within the outer annulus;
calculating a statistical parameter using the plurality of measurements; and
providing an indication of plugging based upon the statistical parameter.
15. The method of claim 14 , wherein the method is performed by a pressure transmitter.
16. The method of claim 14 , wherein the statistical parameter is mean.
17. The method of claim 14 , wherein the statistical parameter is standard deviation.
18. A gas-lift oil well comprising:
a first pipe having a first pipe wall defining an interior adapted to convey pressurized crude oil;
a second pipe having a second pipe wall defining an inner annulus with the first pipe wall;
an outer shell defining an outer annulus with the second pipe wall; and
means for detecting plugging of the outer annulus.
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
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US11/050,637 US20050173112A1 (en) | 2004-02-05 | 2005-02-03 | Annulus plugging detection using a pressure transmitter in gas-lift oil production |
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US54218504P | 2004-02-05 | 2004-02-05 | |
US11/050,637 US20050173112A1 (en) | 2004-02-05 | 2005-02-03 | Annulus plugging detection using a pressure transmitter in gas-lift oil production |
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US20050173112A1 true US20050173112A1 (en) | 2005-08-11 |
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US11/050,637 Abandoned US20050173112A1 (en) | 2004-02-05 | 2005-02-03 | Annulus plugging detection using a pressure transmitter in gas-lift oil production |
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EP (1) | EP1711681B1 (en) |
JP (1) | JP2007520656A (en) |
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CA (1) | CA2547974A1 (en) |
DE (1) | DE602005009493D1 (en) |
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Cited By (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20100011869A1 (en) * | 2007-07-20 | 2010-01-21 | Rosemount Inc. | Differential pressure diagnostic for process fluid pulsations |
US7765873B2 (en) | 2007-07-20 | 2010-08-03 | Rosemount Inc. | Pressure diagnostic for rotary equipment |
US7949495B2 (en) * | 1996-03-28 | 2011-05-24 | Rosemount, Inc. | Process variable transmitter with diagnostics |
US20110259095A1 (en) * | 2008-12-16 | 2011-10-27 | Mcmiles Barry J | Hydraulic Signature Tester |
Families Citing this family (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
CN110185415A (en) * | 2018-05-09 | 2019-08-30 | 中国科学院深海科学与工程研究所 | Petroleum pipeline dredging system and dredging method |
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2005
- 2005-02-03 JP JP2006552205A patent/JP2007520656A/en not_active Withdrawn
- 2005-02-03 US US11/050,637 patent/US20050173112A1/en not_active Abandoned
- 2005-02-03 EP EP05712602A patent/EP1711681B1/en not_active Not-in-force
- 2005-02-03 RU RU2006131692/03A patent/RU2359117C2/en active
- 2005-02-03 CN CNA2005800023661A patent/CN1910338A/en active Pending
- 2005-02-03 DE DE602005009493T patent/DE602005009493D1/en not_active Expired - Fee Related
- 2005-02-03 WO PCT/US2005/003218 patent/WO2005078237A1/en active Application Filing
- 2005-02-03 CA CA002547974A patent/CA2547974A1/en not_active Abandoned
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Cited By (8)
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US7949495B2 (en) * | 1996-03-28 | 2011-05-24 | Rosemount, Inc. | Process variable transmitter with diagnostics |
US20100011869A1 (en) * | 2007-07-20 | 2010-01-21 | Rosemount Inc. | Differential pressure diagnostic for process fluid pulsations |
US7765873B2 (en) | 2007-07-20 | 2010-08-03 | Rosemount Inc. | Pressure diagnostic for rotary equipment |
US7770459B2 (en) | 2007-07-20 | 2010-08-10 | Rosemount Inc. | Differential pressure diagnostic for process fluid pulsations |
US20110259095A1 (en) * | 2008-12-16 | 2011-10-27 | Mcmiles Barry J | Hydraulic Signature Tester |
US8240199B2 (en) * | 2008-12-16 | 2012-08-14 | Mcmiles Barry James | Hydraulic signature tester |
US20120283966A1 (en) * | 2008-12-16 | 2012-11-08 | Mcmiles Barry James | Hydraulic Signature Tester |
US9631479B2 (en) * | 2008-12-16 | 2017-04-25 | Barry James McMiles | Hydraulic signature tester |
Also Published As
Publication number | Publication date |
---|---|
EP1711681B1 (en) | 2008-09-03 |
JP2007520656A (en) | 2007-07-26 |
RU2006131692A (en) | 2008-03-10 |
DE602005009493D1 (en) | 2008-10-16 |
EP1711681A1 (en) | 2006-10-18 |
CN1910338A (en) | 2007-02-07 |
RU2359117C2 (en) | 2009-06-20 |
CA2547974A1 (en) | 2005-08-25 |
WO2005078237A1 (en) | 2005-08-25 |
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