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Publication numberUS20050173112 A1
Publication typeApplication
Application numberUS 11/050,637
Publication dateAug 11, 2005
Filing dateFeb 3, 2005
Priority dateFeb 5, 2004
Also published asCA2547974A1, CN1910338A, DE602005009493D1, EP1711681A1, EP1711681B1, WO2005078237A1
Publication number050637, 11050637, US 2005/0173112 A1, US 2005/173112 A1, US 20050173112 A1, US 20050173112A1, US 2005173112 A1, US 2005173112A1, US-A1-20050173112, US-A1-2005173112, US2005/0173112A1, US2005/173112A1, US20050173112 A1, US20050173112A1, US2005173112 A1, US2005173112A1
InventorsKadir Kavaklioglu, Marcos Peluso
Original AssigneeKadir Kavaklioglu, Marcos Peluso
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Annulus plugging detection using a pressure transmitter in gas-lift oil production
US 20050173112 A1
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.
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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.
Description
CROSS-REFERENCE TO RELATED APPLICATION

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.

BACKGROUND OF THE INVENTION

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 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. By the nature of this process, 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. In an ideal situation, the pressure within outer 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 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.

One factor that complicates monitoring the pressure within outer annulus 22 is material disposed within annulus 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 in FIG. 1, a pressure transmitter, such as transmitter 24 is sometimes operably coupled to outer 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 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 pressures exceeding 4000 pounds per square inch have been observed during this process. Due to the frozen plug at the top of annulus 22, pressure measured using transmitter 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.

SUMMARY OF THE INVENTION

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.

BRIEF DESCRIPTION OF THE DRAWINGS

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.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

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. 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 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 FOUNDATION™ Fieldbus. Power module 112 may also include one or more suitable transducers for converting potential energy into electrical energy for transmitter 100. Thus, 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. In embodiments where transmitter 100 is expected to communicate using an industry standard process communication protocol, module 116 will be suitably adapted. For example, if transmitter 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 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.

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 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.

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, 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.

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.

Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US7765873Jul 18, 2008Aug 3, 2010Rosemount Inc.Pressure diagnostic for rotary equipment
US7770459Jul 18, 2008Aug 10, 2010Rosemount Inc.Differential pressure diagnostic for process fluid pulsations
US7949495 *Aug 17, 2005May 24, 2011Rosemount, Inc.Process variable transmitter with diagnostics
US8240199 *Dec 15, 2009Aug 14, 2012Mcmiles Barry JamesHydraulic signature tester
US20110259095 *Dec 15, 2009Oct 27, 2011Mcmiles Barry JHydraulic Signature Tester
Classifications
U.S. Classification166/250.01, 166/66, 166/372
International ClassificationE21B47/00, E21B47/06, G01F1/50, E21B43/12
Cooperative ClassificationE21B47/06, E21B43/122
European ClassificationE21B43/12B2, E21B47/06
Legal Events
DateCodeEventDescription
Apr 7, 2005ASAssignment
Owner name: ROSEMOUNT INC., MINNESOTA
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:KAVAKLIOGLU, KADIR;PELUSO, MARCOS;REEL/FRAME:016436/0898;SIGNING DATES FROM 20050318 TO 20050402