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Publication numberUS3908761 A
Publication typeGrant
Publication dateSep 30, 1975
Filing dateAug 5, 1974
Priority dateMay 2, 1973
Publication numberUS 3908761 A, US 3908761A, US-A-3908761, US3908761 A, US3908761A
InventorsPatterson Maurice M, Sheffield Bass C
Original AssigneeShell Oil Co
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Method for determining liquid production from a well
US 3908761 A
A method for determining the liquid flow in a pipe having turbulent flow, for example, two-phase flow wherein the dynamic pressure fluctuations are measured, and converted to a useful signal. The root mean square of the signal is obtained and integrated over a specific time interval to obtain the liquid flow in the pipe.
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Description  (OCR text may contain errors)

Hawaii Patterson et al.

[ 1 Sept. 30, 1975 [54] METHOD FOR DETERMINING LIQUID 3.643.740 2/1972 Kelley 166/314 X PRODUCTION FROM A WELL 1653.717 4/1972 Rich Ct 211. 166/314 X 3,705,532 12/1972 Hubby 166/314 X [75] inventors: Maurice M. Patterson, Houston;

$358 C. Sheffield, 8611211113. 13011] Of ex 150,656 I 12/1962 U.S.S.R. 73/194 B [73] Assignee: Shell Oil Company, Houston, Tex.

1221 Filed: 1974 Primary E.\'aminerStephen J. Novosad [21] Appl. No.: 494,581

Related US. Application Data [62] Division of Ser. No. 356.650. May 2, 1973. Pat. No. [57] ABSTRACT v A method for determining the liquid flow in a pipe [s7] U S Cl 166/250 166/314. 73 having turbulent flow, for example, two-phase flow 5; EzlB 66 wherein the dynamic pressure fluctuations are mea- {581 Field 314 sured, and converted to a useful signal. The root mean fifl square of the signal is obtained and integrated over a specific time interval to obtain the liquid flow in the [56] References Cited pipe UNITED STATES PATENTS 3 Claims, 8 Drawing Figures $219,107 11/1965 Brown. Jr. et a1. 166/250 L i 11 DYNAMIC PRESSURE TRANSDUCER COUPLER I8 I IN TEGRA TOR ,7 I5 VAR/A BLE 5 RMS TIME CONVERSION CONSMN T5 79 STRIP CHART RECORDER U.S. Patent Sept. 50,1975 Sheet1of4 3,908,761



c I l l 0 50 I00 I50 200 250 300 PSM READING, mv

US. Patent Sept. 30,1975 Sheet 2 of4 3,908,761



U.S. Patent Sept. 30,1975 Sheet 3 of4 3,908,761

TIME (SECONDS) US. Patent Sept. 30,1975 Sheet4 0f4 3,908,761

\WQZOUMMQ NSC my R w m w m N m GE METHOD FOR DETERMINING LIQUID PRODUCTION FROM A WELL CROSS-REFERENCE This is a division of application Ser.-No..356,650, filed May 2, 1973 now US. Pat. No. 3.834,227.

BACKGROUND OF THE INVENTION The present invention relates to a method for deter mining the liquid flow from a well and particularly the liquid flow in an oil well having turbulent slug or twophase flow. In a large portion of the producing oil wells, some means of artificiallifting is used. For example, the well can be pumped by either a rod driven pump or hydraulic pump or a gas lift system can be used. In the case of gas lift, gas is transmitted down the well under high pressure and used to lift the oil to the surface. In a gas lift well the oil flows to the surface in the form of discrete slugs separated by gas. Of course, in the case of a pumped well, the oil is pumped directly to the surface in a semi-continuous flow until the well is pumped dry at which point the pump will either pump air or be shut down.

In all of the above-described artificial lifting systems, it is desirable to know the quantity of liquid actually produced at the surface. For example, in the case of a gas lift well, if too much gas is transmitted to the bottom, the gas will tend to disperse into the liquid phase and reduce the quantity of the oil lifted to the surface. Likewise, if too little gas is transmitted to the bottom of the hole, the quantity of oil lifted to the surface will be smaller. Thus. the adjustment of the gas lift system for the optimum flow of gas is highly desirable to obtain the maximum efficiency of the system while producing the maximum amount of oil. Similarly, in the case of pumped wells, it is desirable to know when the well has been pumped dry so that the pump can be secured until the well again fills with liquid. This, of course, conserves the. energy required for driving the pumping means and improves the efficiency.

BRIEF DESCRIPTION OF THE INVENTION The present invention is based on the discovery that the variation in the fluid pressure during turbulent flow can be correlated with the total liquid flow in a slug or two-phase flow. Turbulent flow occurs at Reynolds numbers of 2000 to 3000 and test results have confirmed that variation in pressure is linear for Reynolds numbers above approximately 20,000. While best results are obtained for Reynolds numbers above 20,000, results have been obtained for Reynolds numbers in the range of 5000. The pressure turbulence ofa liquid is to 100 times that of gas flow, thus the device is relatively insensitive to gas flow. While the accuracy of the system is in the neighborhood of plus or minus 10%, this is satisfactory for many operations. This is especially the case where the information is used to improve the production efficiency of an oil well and is not relied upon for determining the actual production of the wells for accounting purposes.

The apparatus used in practicing the invention consists of a piezoelectric dynamic pressure transducer, a circuit for converting the electrical signal from the transducer to a RMS signal and an integrating network for integrating the RMS signal. The pressure transducer responds to fluctuations above approximately 1 Hz and does not respond to static pressure or slow changes in line pressure. vibrations. or temperature. Thus. the transducer produces an output signal only when aliquid slug passes the transducer and does not appreciably respond to gas flow. The RMS signal is related to the actual energy in the signal which can be used to determine the total liquid flow and one only needs to integrate the RMS signal over a time period to obtain an indication of the total flow from the well.

The signal from the circuit indicating total flow can be used for adjusting the gas flow in a gas lift well or the length of the pumping periods in a pumped well. Of course, it is also possible to use the system for measuring the flow of water into an injection or disposal well. Normally, injection wells are designed for a certain flow rate and a change in this flow rate indicates either a change in the reservoir into which the water is injected or a breakdown in the injection equipment at the surface.

. BRIEF DESCRIPTION OF THE DRAWINGS The present invention will be more easily understood from the following detailed description taken in conjunction with the attached drawings in which:

FIG. 1 is a blocked diagram of the apparatus used for practicing the method;

FIG. 2 is a plot of the total RMS energy versus Reynolds numbers;

FIG. 3 is a plot of the RMS energy versus various frequencies;

FIG. 4 shows the actual signal produced by the transducer and the corresponding RMS signal;

FIG. 5 is: a signal from a second well showing the transducer signal and the RMS signal;

FIG. 6' shows the'same well as in FIG. 5 but the well has been pumped off and there is no liquid flow;

FIG. 7 shows the relationship between liquid production and the RMS signal; and

FIG. 8 shows the relationship between liquid production and the RMS signal for a separate set of values.

DESCRIPTION OF THE PREFERRED EMBODIMENTS Referring now to FIG. 1. there is shown a block diagram of a system suitable for practicing the method of this invention. There is shown afluid production line 10 which can be the production line from an oil well under some manner of artificial lift as, for example, a gaslift, a rod pump well, a hydraulically pumped well, or submersible pumped well. The production line 10 can also be the injection line well. While the above terms "oil well" is used to simplify the description of the invention, the invention is adaptable to any well having turbulent slug or two-phase flow and is not limited to a conventional oil well where the gas to liquid ratio is in the range of l to 100.

A pressure transducer 11 is mounted on the production line 10 to sense changes in the pressure of the liquid flowing in the line. The pressure transducer may be mounted in a conventional sample port on the line and does not project into the interior of the line. In oil field installations, it is desirable to maintain production lines free of obstructions so that through-the-flowline tools may be circulated. Of course, pressure changes will only occur when there is turbulent flow in the line. When the fluid flow occurs at Reynolds numbers below 20,000, the fluid flow measured by the invention will not be linear and the system must be calibrated. Likewise. in case of gas flow where pressure changes are very small, the pressure transducer will not sense the change. Any dynamic type of pressure transducer that supplies an electric signal related to the instantaneous changes in the pressure can be used. For example. a transducer sold under the name Kistler Model 205 H-l manufactured by the Kistler Instrument Company of Redmond, Washington. can be used. Similar piezoelectric transducers, magnetostrictive transducers. or magneto electric transducers could also be used. The dynamic pressure transducer is mounted in a port formed in the wall of the production line 10. Since the transducer responses to dynamic pressure changes. it need not project into the production line. Thus, through-theflowline tools may be passed through the production line without removing the transducer. The electrical signal from the transducer is supplied to a coupling device 13 which may be a part of the transducer itself with the coupling device being connected by a coaxial cable 14 to a RMS conversion circuit 15. The coupling device 13 matches the high impedance signal from the transducer to the input circuit ofthe root means square or RMS conversion circuit 15. The RMS circuit may be a traditional volt meter which converts a fluctuating voltage to an RMS signal. The RMS circuit is connected by a lead 17 to an integrator 18 whose output signal is recorded on a strip chart recorder 19.

The above system can be fabricated from commercially available parts or a specially designed system can be used. The data collected on the strip chart recorder I9 can either be analyzed in the field visually or can be transmitted in the form of digital or analog data to a central location where it can be analyzed in more detail or by sophisticated analysis. Likewise. the signal from the integrator 18 can be supplied to a simple computer which in turn controls the lift mechanism for the well. For example, the computer may consist of a conventional process controller 20 whose set point 2] is adjusted for the optimum liquid production from the well and whose output controls the lift mechanism. Of course. in the case of a mechanically pumped well. the set point could be adjusted for a minimum liquid flow and when the actual liquid flow from the well falls below the set point. the process controller would secure the pumping unit for a predetermined time interval to allow the well to fill. The output signal from the process controller 20 is used to control the operation of the artificial lift control 22. The artificial lift control may be the power switch for a pump unit on the flow control for the gas supply in a gas lift well.

Referring to FIG. 2, there is shown a plot of the value of the RMS signal versus various Reynolds numbers. As can be seen in the range of Reynolds numbers of 20,000 and greater, the RMS signal is substantially linear. Thus, one can use the RMS signal as a measure of liquid flow. Of course. the actual liquid flow in volumetric measurement will be equal to the RMS signal times a constant wherein the constant is related to the density of the liquid and the size of the pipeline.

FIG. 3 illustrates the relationship between the RMS energy in the signal and the various frequencies of the signal. As can be seen at approximately Hz. there is a large difference between the flow rates corresponding to Reynolds numbers of 20,000 to 50.000. Thus. it is possible to accurately determine the fluid flow in the flowline from the variations in the energy level of the RMS signal.

Referring now to FIG. 4. there is shown a portion of a signal from a gas lift well wherein the signal A represents the signal produced by the transducer while the signal B shows the RMS signal. In addition. there is shown the time interval of 1 second. If one integrates the RMS signal. one will obtain the total flow from the well. Also. one can count the times that the RMS signal has values above the base line which indicate the number of slugs of liquid passing through the production flowline. From this information one can determine whether the gas flow should be increased or decreased.

FIG. 5 illustrates signals similar to those shown in FIG. 4 but for a well having a high flow rate. As can be seen in signal B of FIG. 4, the pressure pulsations are almost continuous and the intervals between the slugs ofliquid and the gas slugs are considerably shorter. Still it is possible to count the slugs of liquid and take appropriate action.

FIG. 6 illustrates the same well as shown in FIG, 5 but for the condition where substantially all the liquid has been removed from the reservoir. In this condition, there is substantially no liquid and RMS signal is substantially zero. This would indicate substantially zero production from the well. While the RMS signal does have slight amplitude excursions. the total integrated area of the signals would be well within the plus or minus 10% accuracy of the instrument. As explained in the introduction, this accuracy is within the requirements for controlling the production of the average oil well.

FIGS. 7 and 8 illustrate the relationship between the RMS signal output in millivolts and the production of liquids. i.e.. oil plus water in barrels per day. From these figures, one can correlate the data recorded on the strip chart recorder of FIG. I to obtain an actual reading in barrels of liquid per day.

We claim as our invention:

1. A method for controlling the operation of an artificially lifted oil well comprising:

measuring at the surface fluctuations in the pressure of the fluid flow from the well;

measuring the RMS value of the fluctuations;

integrating the RMS signal occurring in a predetermined time period to obtain a signal related to the liquid flow from the well; comparing said integrated signal with a pre-set signal representing the desired liquid flow from the well over the time period to obtain an error signal; and

controlling the artificial lift means in response to said error signal.

2. The method of claim 1 wherein the well is a gas lift well and the quantity of gas injected into the well is controlled.

3. The method of claim 1 wherein the well is a rod pumped well and the on and off cycle of the pump is controlled.

Patent Citations
Cited PatentFiling datePublication dateApplicantTitle
US3219107 *Sep 14, 1960Nov 23, 1965Socony Mobil Oil Co IncRemote and automatic control of petroleum production
US3643740 *Apr 28, 1969Feb 22, 1972Kelley KorkMethod and apparatus for effecting gas control in oil wells
US3653717 *Sep 29, 1969Apr 4, 1972Exxon Production Research CoArtificial lift system
US3705532 *May 21, 1970Dec 12, 1972Texaco IncMethods for controlling pumping wells
Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US4046220 *Mar 22, 1976Sep 6, 1977Mobil Oil CorporationMethod for distinguishing between single-phase gas and single-phase liquid leaks in well casings
US4393485 *May 2, 1980Jul 12, 1983Baker International CorporationApparatus for compiling and monitoring subterranean well-test data
US4475591 *Aug 6, 1982Oct 9, 1984Exxon Production Research Co.Method for monitoring subterranean fluid communication and migration
US5014789 *Jul 7, 1987May 14, 1991Neville ClarkeMethod for startup of production in an oil well
US5608170 *Feb 22, 1993Mar 4, 1997Schlumberger Technology CorporationFlow measurement system
US5915932 *Feb 6, 1996Jun 29, 1999Isco, Inc.Peristaltic pump having a roller support
US6354345Jun 28, 1999Mar 12, 2002Isco, Inc.Pumping system
US7406398 *Jun 5, 2004Jul 29, 2008Schlumberger Technology CorporationSystem and method for determining pump underperformance
US20050251362 *Jun 5, 2004Nov 10, 2005Ollre Albert GSystem and method for determining pump underperformance
EP0440320A1 *Jan 28, 1991Aug 7, 1991ISCO, Inc.Pumping system
EP2581714A1Oct 10, 2012Apr 17, 2013systec Controls Mess- und Regeltechnik GmbHMethod for determining an absolute flow velocity of a volume or mass flow
WO1992001908A1 *Jul 18, 1991Feb 6, 1992Secretary Trade Ind BritTwo-phase flow measurement
WO1993017305A1 *Feb 22, 1993Sep 2, 1993Schlumberger Ca LtdFlow measurement system
U.S. Classification166/250.1, 73/152.42, 166/372, 73/152.29
International ClassificationE21B47/10, G01F1/34, E21B43/12, G01F1/74, F04B49/10
Cooperative ClassificationE21B43/121, E21B47/10, G01F1/74, E21B43/12, F04B49/106, G01F1/34
European ClassificationE21B43/12, E21B43/12B, E21B47/10, G01F1/34, G01F1/74, F04B49/10V