CA2762269C - Method and apparatus for determining a level of a fluid in communication with a downhole pump - Google Patents
Method and apparatus for determining a level of a fluid in communication with a downhole pump Download PDFInfo
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- CA2762269C CA2762269C CA2762269A CA2762269A CA2762269C CA 2762269 C CA2762269 C CA 2762269C CA 2762269 A CA2762269 A CA 2762269A CA 2762269 A CA2762269 A CA 2762269A CA 2762269 C CA2762269 C CA 2762269C
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- pump
- vibration
- generate
- fluid level
- values
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Classifications
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- 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
- E21B47/008—Monitoring of down-hole pump systems, e.g. for the detection of "pumped-off" conditions
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- 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
- E21B47/04—Measuring depth or liquid level
- E21B47/047—Liquid level
Abstract
A method and apparatus for determining a level of a fluid in communication with a downhole pump during a pumping operation is disclosed. The method involves receiving a signal representing pump vibrations generated by operation of the pump during the pumping operation, and based on the signal, generating a vibration value characterizing the pump vibrations. The method also involves using a correlation between pump vibrations and fluid level to generate a fluid level value corresponding to the vibration value.
Description
METHOD AND APPARATUS FOR DETERMINING A LEVEL OF A FLUID IN
COMMUNICATION WITH A DOWNHOLE PUMP
BACKGROUND OF THE INVENTION
1. Field of Invention This invention relates generally to determining fluid level and more particularly to determining a fluid level in communication with a downhole pump.
COMMUNICATION WITH A DOWNHOLE PUMP
BACKGROUND OF THE INVENTION
1. Field of Invention This invention relates generally to determining fluid level and more particularly to determining a fluid level in communication with a downhole pump.
2. Description of Related Art Downhole pumps may be used to pump fluids out of reservoirs. For example, in hydrocarbon recovery operations, it is common to drill a borehole into an oil reservoir for extracting the hydrocarbons from the reservoir. In operations where the natural pressure of the reservoir is not high enough to cause the hydrocarbon fluids to flow to the surface, artificial lift may be employed to produce the fluids to the surface. One example of an artificial lift system is an electric submersible pump (ESP), which may be disposed at the end of a tubing string, which is lowered into the borehole until the ESP is submerged in the fluid. In such operations there can be some difficulty in determining the fluid level around or proximate an intake of the pump.
It is desirable that the electric submersible pump be operated such that the accumulated fluid is above the intake by a sufficient height to prevent the pump from drawing air. On the other hand, it is also desirable that fluid does not accumulate to a level too far above the intake, since the resulting increased hydrostatic pressure in the well may reduce production of fluid from the surrounding reservoir, thus reducing production of fluid to the surface.
SUMMARY OF THE INVENTION
In accordance with one aspect of the invention there is provided a method for determining a level of a fluid in communication with a downhole pump during a pumping operation. The method involves receiving a signal representing pump vibrations generated by operation of the pump during the pumping operation, and based on the signal, generating a vibration value characterizing the pump vibrations. The method also involves using a correlation between pump vibrations and fluid level to generate a fluid level value corresponding to the vibration value.
Receiving the signal may involve receiving the signal from a vibration transducer configured to receive pump vibrations and to generate the signal representing the pump vibrations.
The vibration transducer may be coupled to a conduit that is coupled to the pump, the conduit being operable to transmit pump vibrations from the pump to the transducer.
The vibration transducer may be coupled to an electrical conduit housing an electrical cable for supplying electrical power to the pump.
The pump may include an outlet for discharging fluid from the pump and the conduit may include production tubing extending between an outlet of the pump and a wellhead disposed at the surface, and the vibration transducer may be coupled to the production tubing at a location spaced apart from the outlet of the pump along the production tubing.
It is desirable that the electric submersible pump be operated such that the accumulated fluid is above the intake by a sufficient height to prevent the pump from drawing air. On the other hand, it is also desirable that fluid does not accumulate to a level too far above the intake, since the resulting increased hydrostatic pressure in the well may reduce production of fluid from the surrounding reservoir, thus reducing production of fluid to the surface.
SUMMARY OF THE INVENTION
In accordance with one aspect of the invention there is provided a method for determining a level of a fluid in communication with a downhole pump during a pumping operation. The method involves receiving a signal representing pump vibrations generated by operation of the pump during the pumping operation, and based on the signal, generating a vibration value characterizing the pump vibrations. The method also involves using a correlation between pump vibrations and fluid level to generate a fluid level value corresponding to the vibration value.
Receiving the signal may involve receiving the signal from a vibration transducer configured to receive pump vibrations and to generate the signal representing the pump vibrations.
The vibration transducer may be coupled to a conduit that is coupled to the pump, the conduit being operable to transmit pump vibrations from the pump to the transducer.
The vibration transducer may be coupled to an electrical conduit housing an electrical cable for supplying electrical power to the pump.
The pump may include an outlet for discharging fluid from the pump and the conduit may include production tubing extending between an outlet of the pump and a wellhead disposed at the surface, and the vibration transducer may be coupled to the production tubing at a location spaced apart from the outlet of the pump along the production tubing.
-3-The vibration transducer may include a plurality of vibration transducers disposed at spaced apart locations along the production tubing and receiving the signal may involve receiving signals from each of the vibration transducers, each signal representing pump vibrations at the respective transducer locations along the production tubing and the generating the vibration values may involve combining values from the signals to generate the values characterizing the pump vibrations.
The pump may include an inlet in communication with fluid produced from a steam assisted gravity drainage well.
Generating the vibration value may involve processing the signal to generate amplitude values representing an amplitude of the pump vibrations.
Processing the signal to generate the amplitude values may involve processing the signal to generate root mean square (RMS) amplitude values.
The method may involve averaging the RMS amplitude values over a time period to generate an average value representing pump vibrations during the time period.
Using the correlation between pump vibrations and fluid level may involve applying a predetermined relationship between pump vibration amplitude values and fluid level values to generate the fluid level value.
Generating the vibration value may involve processing the signal to generate frequency spectrum indicia values and using the correlation between pump vibrations and fluid level may involve using a predetermined correlation between
The pump may include an inlet in communication with fluid produced from a steam assisted gravity drainage well.
Generating the vibration value may involve processing the signal to generate amplitude values representing an amplitude of the pump vibrations.
Processing the signal to generate the amplitude values may involve processing the signal to generate root mean square (RMS) amplitude values.
The method may involve averaging the RMS amplitude values over a time period to generate an average value representing pump vibrations during the time period.
Using the correlation between pump vibrations and fluid level may involve applying a predetermined relationship between pump vibration amplitude values and fluid level values to generate the fluid level value.
Generating the vibration value may involve processing the signal to generate frequency spectrum indicia values and using the correlation between pump vibrations and fluid level may involve using a predetermined correlation between
-4-reference frequency spectrum indicia and fluid level values to generate the fluid level value.
Processing the signal to generate the frequency spectrum indicia may involve determining a fundamental frequency of the pump vibrations.
Using the correlation between pump vibrations and fluid level to generate the fluid level value may involve determining a reference fundamental frequency of the pump vibrations under the reference fluid level conditions, and determining a difference between the fundamental vibration frequency and the fundamental vibration frequency of the pump under the reference fluid level conditions.
The pump may include an alternating current motor coupled to a variable frequency drive for providing drive power to the motor and generating the fluid level value may involve determining a frequency offset between the fundamental frequency of the pump vibrations and a frequency of the drive power supplied to the motor.
The pump may include a reciprocating piston pump coupled to an actuator operable to provide a reciprocating drive for driving the pump and generating the fluid level value may involve determining a frequency offset between the fundamental frequency of the pump vibrations and an operating frequency associated with the actuator.
The method may involve generating the correlation between pump vibrations and fluid level.
Processing the signal to generate the frequency spectrum indicia may involve determining a fundamental frequency of the pump vibrations.
Using the correlation between pump vibrations and fluid level to generate the fluid level value may involve determining a reference fundamental frequency of the pump vibrations under the reference fluid level conditions, and determining a difference between the fundamental vibration frequency and the fundamental vibration frequency of the pump under the reference fluid level conditions.
The pump may include an alternating current motor coupled to a variable frequency drive for providing drive power to the motor and generating the fluid level value may involve determining a frequency offset between the fundamental frequency of the pump vibrations and a frequency of the drive power supplied to the motor.
The pump may include a reciprocating piston pump coupled to an actuator operable to provide a reciprocating drive for driving the pump and generating the fluid level value may involve determining a frequency offset between the fundamental frequency of the pump vibrations and an operating frequency associated with the actuator.
The method may involve generating the correlation between pump vibrations and fluid level.
-5-Generating the correlation may involve obtaining reference vibration values associated with operating the pump under reference fluid level conditions.
Obtaining reference vibration values may involve determining the reference fluid level by performing a fluid level measurement that is independent of pump vibration, receiving a reference signal representing pump vibration under the reference pump operating conditions, and generating the reference vibration values based on the reference signal.
Obtaining reference vibration values may involve obtaining reference vibration amplitude values.
Obtaining reference vibration values may involve obtaining reference frequency spectrum indicia values.
Obtaining the reference vibration values may involve obtaining reference vibration values associated with operating the pump in communication with a reference fluid having reference fluid constitution and using the correlation may involve determining a constitution of the fluid in communication with the pump, and applying a correction to the correlation for a fluid of the determined constitution.
In accordance with another aspect of the invention there is provided an apparatus for determining a level of a fluid in communication with a downhole pump during a pumping operation. The apparatus includes a receiver operably configured to receive a signal representing pump vibrations generated by operation of the pump during the pumping operation. The apparatus also includes a signal processor operably configured to generate a vibration value
Obtaining reference vibration values may involve determining the reference fluid level by performing a fluid level measurement that is independent of pump vibration, receiving a reference signal representing pump vibration under the reference pump operating conditions, and generating the reference vibration values based on the reference signal.
Obtaining reference vibration values may involve obtaining reference vibration amplitude values.
Obtaining reference vibration values may involve obtaining reference frequency spectrum indicia values.
Obtaining the reference vibration values may involve obtaining reference vibration values associated with operating the pump in communication with a reference fluid having reference fluid constitution and using the correlation may involve determining a constitution of the fluid in communication with the pump, and applying a correction to the correlation for a fluid of the determined constitution.
In accordance with another aspect of the invention there is provided an apparatus for determining a level of a fluid in communication with a downhole pump during a pumping operation. The apparatus includes a receiver operably configured to receive a signal representing pump vibrations generated by operation of the pump during the pumping operation. The apparatus also includes a signal processor operably configured to generate a vibration value
-6-characterizing the pump vibrations based on the signal. The apparatus further includes a comparator operably configured to use a correlation between pump vibrations and fluid level to generate a fluid level value corresponding to the vibration value.
The apparatus may include a vibration transducer configured to receive pump vibrations and to generate the signal representing the pump vibrations.
The vibration transducer may be coupled to a conduit that is coupled to the pump, the conduit being operable to transmit pump vibrations from the pump to the transducer.
The vibration transducer may be coupled to an electrical conduit housing an electrical cable for supplying electrical power to the pump.
The pump may include an outlet for discharging fluid from the pump and the conduit may include production tubing extending between an outlet of the pump and a wellhead disposed at the surface, and the vibration transducer may be coupled to the production tubing at a location spaced apart from the outlet of the pump along the production tubing.
The vibration transducer may include a plurality of vibration transducers disposed at spaced apart locations along the production tubing and operably configured to generate respective signals, each signal representing pump vibrations at the respective transducer locations along the production tubing and the signal processor may be operably configured to generate the vibration value by combining values from the signals to generate the values characterizing the pump vibrations.
The apparatus may include a vibration transducer configured to receive pump vibrations and to generate the signal representing the pump vibrations.
The vibration transducer may be coupled to a conduit that is coupled to the pump, the conduit being operable to transmit pump vibrations from the pump to the transducer.
The vibration transducer may be coupled to an electrical conduit housing an electrical cable for supplying electrical power to the pump.
The pump may include an outlet for discharging fluid from the pump and the conduit may include production tubing extending between an outlet of the pump and a wellhead disposed at the surface, and the vibration transducer may be coupled to the production tubing at a location spaced apart from the outlet of the pump along the production tubing.
The vibration transducer may include a plurality of vibration transducers disposed at spaced apart locations along the production tubing and operably configured to generate respective signals, each signal representing pump vibrations at the respective transducer locations along the production tubing and the signal processor may be operably configured to generate the vibration value by combining values from the signals to generate the values characterizing the pump vibrations.
-7-The pump may include an inlet in communication with fluid produced from a steam assisted gravity drainage well.
The signal processor may be operably configured generate the vibration value by processing the signal to generate amplitude values representing an amplitude of the pump vibrations.
The signal processor may be operably configured to process the signal to generate root mean square (RMS) amplitude values.
The signal processor may be operably configured to average the RMS amplitude values over a time period to generate an average value representing pump vibrations during the time period.
The comparator may be operably configured to apply a predetermined relationship between pump vibration amplitude values and fluid level values to generate the fluid level value.
The signal processor may be operably configured to generate the vibration value by processing the signal to generate frequency spectrum indicia values and the comparator may be operably configured to use a predetermined correlation between reference frequency spectrum indicia and fluid level values to generate the fluid level value.
The signal processor may be operably configured to process the signal to generate the frequency spectrum indicia by determining a fundamental frequency of the pump vibrations.
The signal processor may be operably configured generate the vibration value by processing the signal to generate amplitude values representing an amplitude of the pump vibrations.
The signal processor may be operably configured to process the signal to generate root mean square (RMS) amplitude values.
The signal processor may be operably configured to average the RMS amplitude values over a time period to generate an average value representing pump vibrations during the time period.
The comparator may be operably configured to apply a predetermined relationship between pump vibration amplitude values and fluid level values to generate the fluid level value.
The signal processor may be operably configured to generate the vibration value by processing the signal to generate frequency spectrum indicia values and the comparator may be operably configured to use a predetermined correlation between reference frequency spectrum indicia and fluid level values to generate the fluid level value.
The signal processor may be operably configured to process the signal to generate the frequency spectrum indicia by determining a fundamental frequency of the pump vibrations.
-8-The comparator may be operably configured to determine a reference fundamental frequency of the pump vibrations under the reference fluid level conditions, and to determine a difference between the fundamental vibration frequency and the fundamental vibration frequency of the pump under the reference fluid level conditions.
The pump may include an alternating current motor coupled to a variable frequency drive for providing drive power to the motor and the comparator may be operably configured to generate the fluid level value by determining a frequency offset between the fundamental frequency of the pump vibrations and a frequency of the drive power supplied to the motor.
The pump may include a reciprocating piston pump coupled to an actuator operable to provide a reciprocating drive for driving the pump and the comparator may be operably configured to generate the fluid level value by determining a frequency offset between the fundamental frequency of the pump vibrations and an operating frequency associated with the actuator.
The apparatus may include a processing system operably configured to generate the correlation between pump vibrations and fluid level.
The processing system may be operably configured to generate the correlation by obtaining reference vibration values associated with operating the pump under reference fluid level conditions.
The processing system may be operably configured to obtain reference vibration values by determining the reference fluid level by performing a fluid level
The pump may include an alternating current motor coupled to a variable frequency drive for providing drive power to the motor and the comparator may be operably configured to generate the fluid level value by determining a frequency offset between the fundamental frequency of the pump vibrations and a frequency of the drive power supplied to the motor.
The pump may include a reciprocating piston pump coupled to an actuator operable to provide a reciprocating drive for driving the pump and the comparator may be operably configured to generate the fluid level value by determining a frequency offset between the fundamental frequency of the pump vibrations and an operating frequency associated with the actuator.
The apparatus may include a processing system operably configured to generate the correlation between pump vibrations and fluid level.
The processing system may be operably configured to generate the correlation by obtaining reference vibration values associated with operating the pump under reference fluid level conditions.
The processing system may be operably configured to obtain reference vibration values by determining the reference fluid level by performing a fluid level
-9-measurement that is independent of pump vibration, receiving a reference signal representing pump vibration under the reference pump operating conditions, and generating the reference vibration values based on the reference signal.
The processing system may be operably configured to obtain reference vibration amplitude values.
The processing system may be operably configured to obtain reference frequency spectrum indicia values.
The processing system may be operably configured to obtain reference vibration values associated with operating the pump in communication with a reference fluid having reference fluid constitution and the processing system may be further operably configured to determine a constitution of the fluid in communication with the pump, and apply a correction to the correlation for a fluid of the determined constitution.
Certain implementations may have one or more of the following advantages.
Since the fluid level may be produced during operation of the pump, there is no need to interrupt production of a well to perform fluid level determinations.
In another aspect the disclosed embodiments are capable of providing a continuous fluid level, thereby facilitating optimal operation of the pump for extracting produced fluids from a well. In some implementations, vibration transducers may be located at the wellhead thereby avoiding introducing sensors into the borehole, which takes up limited space and may interfere with other downhole tools. In other implementations the vibration transducers may be located away from the downhole pump along the production tubing, avoiding placement of
The processing system may be operably configured to obtain reference vibration amplitude values.
The processing system may be operably configured to obtain reference frequency spectrum indicia values.
The processing system may be operably configured to obtain reference vibration values associated with operating the pump in communication with a reference fluid having reference fluid constitution and the processing system may be further operably configured to determine a constitution of the fluid in communication with the pump, and apply a correction to the correlation for a fluid of the determined constitution.
Certain implementations may have one or more of the following advantages.
Since the fluid level may be produced during operation of the pump, there is no need to interrupt production of a well to perform fluid level determinations.
In another aspect the disclosed embodiments are capable of providing a continuous fluid level, thereby facilitating optimal operation of the pump for extracting produced fluids from a well. In some implementations, vibration transducers may be located at the wellhead thereby avoiding introducing sensors into the borehole, which takes up limited space and may interfere with other downhole tools. In other implementations the vibration transducers may be located away from the downhole pump along the production tubing, avoiding placement of
-10-sensors on the downhole pump where the sensors will be more susceptible to damage.
Other aspects and features of the present invention will become apparent to those ordinarily skilled in the art upon review of the following description of specific embodiments of the invention in conjunction with the accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS
In drawings which illustrate embodiments of the invention, Figure 1 is a cross section of an oil well and an apparatus in accordance with a first embodiment of the invention;
Figure 2 is a block diagram of a processing system shown in Figure 1;
Figure 3 is a block diagram of a processor circuit for implementing the processing system shown in Figure 2;
Figure 4 is a flowchart of a process for determining fluid level implemented on the processor circuit shown in Figure 3; and Figure 5 is a cross section of the oil well shown in Figure 1 and an apparatus in accordance with an alternative embodiment of the invention.
Other aspects and features of the present invention will become apparent to those ordinarily skilled in the art upon review of the following description of specific embodiments of the invention in conjunction with the accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS
In drawings which illustrate embodiments of the invention, Figure 1 is a cross section of an oil well and an apparatus in accordance with a first embodiment of the invention;
Figure 2 is a block diagram of a processing system shown in Figure 1;
Figure 3 is a block diagram of a processor circuit for implementing the processing system shown in Figure 2;
Figure 4 is a flowchart of a process for determining fluid level implemented on the processor circuit shown in Figure 3; and Figure 5 is a cross section of the oil well shown in Figure 1 and an apparatus in accordance with an alternative embodiment of the invention.
-11-DETAILED DESCRIPTION
Downhole pumps are used in a variety of applications including oil recovery operations, conventional water supply boreholes, source water boreholes used in the oil industry for providing source water for processing, and a numerous other applications. An exemplary oil well embodiment is shown generally at 100 in Figure 1. Referring to Figure 1, the oil well 100 includes a borehole 102 and a wellhead 104. The wellhead 104 is disposed at a surface 106 of the well. The borehole 102 may extend far below the surface 106 and may include several casing layers 108 of concrete and steel. A portion 110 of the borehole 102 is in communication with a surrounding reservoir 112 for extraction hydrocarbon fluids from the reservoir. In one embodiment, the portion 110 includes perforations (not shown) through the casing 108 to permit fluids in the surrounding reservoir 112 to pass through the casing into the borehole 102. Alternatively, in the case of a SAGD well, the borehole portion 110 may be in communication with a generally horizontal section of borehole for receiving fluids drained from the reservoir. In SAGD operations, steam is injected into an upper generally horizontal borehole to heat viscous hydrocarbons within the reservoir 112 to cause the hydrocarbons to drain to a lower generally horizontal borehole. Extracted fluids 114 may be accumulated within the borehole 102 as a fluid column and may be produced to the surface 106 by an electric submersible pump (ESP) 116 through a production tubing 136.
The example electric submersible pump 116 shown includes a motor 118, a seal section 120, an intake 122, and a pump section 124. The motor 118 includes an electrical input 126, which is connected to a cable 128 for receiving an electrical drive current. In this embodiment the motor operates on an alternating current power supply provided by a variable frequency drive (VFD) 130 via the cable 128. The pumping speed of the pump 116 is controlled by changing the
Downhole pumps are used in a variety of applications including oil recovery operations, conventional water supply boreholes, source water boreholes used in the oil industry for providing source water for processing, and a numerous other applications. An exemplary oil well embodiment is shown generally at 100 in Figure 1. Referring to Figure 1, the oil well 100 includes a borehole 102 and a wellhead 104. The wellhead 104 is disposed at a surface 106 of the well. The borehole 102 may extend far below the surface 106 and may include several casing layers 108 of concrete and steel. A portion 110 of the borehole 102 is in communication with a surrounding reservoir 112 for extraction hydrocarbon fluids from the reservoir. In one embodiment, the portion 110 includes perforations (not shown) through the casing 108 to permit fluids in the surrounding reservoir 112 to pass through the casing into the borehole 102. Alternatively, in the case of a SAGD well, the borehole portion 110 may be in communication with a generally horizontal section of borehole for receiving fluids drained from the reservoir. In SAGD operations, steam is injected into an upper generally horizontal borehole to heat viscous hydrocarbons within the reservoir 112 to cause the hydrocarbons to drain to a lower generally horizontal borehole. Extracted fluids 114 may be accumulated within the borehole 102 as a fluid column and may be produced to the surface 106 by an electric submersible pump (ESP) 116 through a production tubing 136.
The example electric submersible pump 116 shown includes a motor 118, a seal section 120, an intake 122, and a pump section 124. The motor 118 includes an electrical input 126, which is connected to a cable 128 for receiving an electrical drive current. In this embodiment the motor operates on an alternating current power supply provided by a variable frequency drive (VFD) 130 via the cable 128. The pumping speed of the pump 116 is controlled by changing the
-12-frequency of the alternating current drive to the motor 118, and in this embodiment the VFD 130 includes an input 132 for receiving a control signal for controlling the drive frequency, and hence the pumping speed. It should be understood that a differently configured pump can be used, and the pump 116 shown is but one illustrative example.
During extraction operations of the well 100, fluid flows into the borehole from the reservoir 112, either due to pressure within the reservoir or due to gravity drainage. The accumulated fluid 114 may comprise water, hydrocarbons in a liquid, solid, and/or gaseous state, or any combination thereof. In heavy hydrocarbon extraction, a portion of the hydrocarbons may combine with water, air, and other gaseous products to form froth, at least a portion of which may float to a surface of the fluid column 114 and form a froth layer 134. It is desirable that the pump 116 be operated such that the fluid 114 accumulates to a level L that is located above the intake 122 by a sufficient operating margin height to prevent the pump 116 from drawing gas or froth 134 into the intake. While typical electric submersible pumps will have load sensing system that protect the pump from damage when drawing froth or gas, such events when they occur result in loss of production from the well.
The pump speed control signal received at the input 132 of the VFD 130 may be adjusted by well control system (not shown) or by a well operator based on a current operating level L of the fluid 114. Since the electric submersible pump 116 may be anywhere from a few hundred to several thousands of meters below the surface 106, accurate determination of the level L of fluid 114 is important for efficient production of hydrocarbons from the well 100.
During extraction operations of the well 100, fluid flows into the borehole from the reservoir 112, either due to pressure within the reservoir or due to gravity drainage. The accumulated fluid 114 may comprise water, hydrocarbons in a liquid, solid, and/or gaseous state, or any combination thereof. In heavy hydrocarbon extraction, a portion of the hydrocarbons may combine with water, air, and other gaseous products to form froth, at least a portion of which may float to a surface of the fluid column 114 and form a froth layer 134. It is desirable that the pump 116 be operated such that the fluid 114 accumulates to a level L that is located above the intake 122 by a sufficient operating margin height to prevent the pump 116 from drawing gas or froth 134 into the intake. While typical electric submersible pumps will have load sensing system that protect the pump from damage when drawing froth or gas, such events when they occur result in loss of production from the well.
The pump speed control signal received at the input 132 of the VFD 130 may be adjusted by well control system (not shown) or by a well operator based on a current operating level L of the fluid 114. Since the electric submersible pump 116 may be anywhere from a few hundred to several thousands of meters below the surface 106, accurate determination of the level L of fluid 114 is important for efficient production of hydrocarbons from the well 100.
-13-The well 100 further includes an apparatus 150 for determining a level of the fluid 114 in communication with the pump 116. The apparatus 150 includes a transducer 152 coupled a portion 154 of the well completion structure (in this case to the wellhead 104) for generating a signal representing vibrations generated by the pump 116 during pumping operations. The apparatus 150 also includes a processing system 156 having a transducer signal input 160 for receiving the signal representing vibrations. The processing system 156 is configured to generate a vibration value characterizing the pump vibrations and also includes a fluid level output 168 for producing a signal representing fluid level. In other embodiments the transducer 152 may include a plurality of transducers coupled to the well completion structure. For example, additional transducers may be coupled to downhole portions of the production tubing 136.
An example embodiment of the processing system 156 is shown in Figure 2.
Referring to Figure 2, the processing system 156 includes a receiver 158 having the transducer signal input 160 for receiving a signal representing pump vibrations generated by operation of the pump 116 during pumping operations.
The processing system 156 also includes a signal processor 162 operably configured to process the vibration signals received by the receiver 158 to generate a vibration value characterizing the pump vibrations. The processing system 156 also includes a store 164 for holding a correlation between pump vibrations and fluid level. The processing system 156 further includes comparator 166, which receives the vibration value from the signal processing system 162 and the correlation between pump vibrations and fluid level from the store 164 and generates a fluid level value. The fluid level value is made available at the output 168 of the processor system 156 in an analog or digital signal format suitable for driving a display (not shown), for providing a fluid level readout, or for coupling to a well control system as a control input. In one
An example embodiment of the processing system 156 is shown in Figure 2.
Referring to Figure 2, the processing system 156 includes a receiver 158 having the transducer signal input 160 for receiving a signal representing pump vibrations generated by operation of the pump 116 during pumping operations.
The processing system 156 also includes a signal processor 162 operably configured to process the vibration signals received by the receiver 158 to generate a vibration value characterizing the pump vibrations. The processing system 156 also includes a store 164 for holding a correlation between pump vibrations and fluid level. The processing system 156 further includes comparator 166, which receives the vibration value from the signal processing system 162 and the correlation between pump vibrations and fluid level from the store 164 and generates a fluid level value. The fluid level value is made available at the output 168 of the processor system 156 in an analog or digital signal format suitable for driving a display (not shown), for providing a fluid level readout, or for coupling to a well control system as a control input. In one
-14-embodiment the processing system 156 may be implemented using a microprocessor circuit configured to perform the functions of the blocks 158 -166 shown in Figure 2. Alternatively, the processing system 156 may be implemented using analog and/or logic circuitry, and application specific integrated circuit (ASIC), or a configurable electronic device such as a field-programmable gate array (FPGA) or mixed-signal FPGA, for example.
In one embodiment the processing system 156 may be located at the wellhead 104, but in other embodiments portions of the processing system may be remotely located with respect to the wellhead. For example, in one embodiment the receiver 158 may be located proximate the wellhead 104 for receiving the transducer signal 160, and the receiver 158 may further include an interface (not shown) for communicating either wirelessly or over a wired connection with a remotely located signal processor 162, and/or comparator 166 and/or correlation store 164. In such embodiments the determination of the fluid level could be performed remotely and transmitted back to the wellhead 104.
In the embodiment shown in Figure 1, the transducer signal (received at the input 160 of the processing system 156) is provided by the transducer 152, which is coupled to receive vibrations from portion 154 of the wellhead 104. In this embodiment, the transducer 152 is located at the surface, and pump vibrations are transmitted from the pump 116 along the production tubing 136 to the wellhead 104. Alternatively, the vibration transducer 152 may be coupled to receive vibrations along an electric cable connection to the pump, either through a cable sheath or through the cable conductors. In other embodiments the vibration transducer 152 may be located downhole proximate the electric submersible pump 166, or at another location along the production tubing 136
In one embodiment the processing system 156 may be located at the wellhead 104, but in other embodiments portions of the processing system may be remotely located with respect to the wellhead. For example, in one embodiment the receiver 158 may be located proximate the wellhead 104 for receiving the transducer signal 160, and the receiver 158 may further include an interface (not shown) for communicating either wirelessly or over a wired connection with a remotely located signal processor 162, and/or comparator 166 and/or correlation store 164. In such embodiments the determination of the fluid level could be performed remotely and transmitted back to the wellhead 104.
In the embodiment shown in Figure 1, the transducer signal (received at the input 160 of the processing system 156) is provided by the transducer 152, which is coupled to receive vibrations from portion 154 of the wellhead 104. In this embodiment, the transducer 152 is located at the surface, and pump vibrations are transmitted from the pump 116 along the production tubing 136 to the wellhead 104. Alternatively, the vibration transducer 152 may be coupled to receive vibrations along an electric cable connection to the pump, either through a cable sheath or through the cable conductors. In other embodiments the vibration transducer 152 may be located downhole proximate the electric submersible pump 166, or at another location along the production tubing 136
-15-and the signal may be transmitted to the surface 106 wirelessly, or through a cable or optical fiber (not shown).
In some implementations, the processing system 156 can be implemented as a microprocessor circuit. An example microprocessor circuit embodiment of the processing system 156 is shown in Figure 3 at 250. Referring to Figure 3, the processor circuit 250 includes a microprocessor 252, a program memory 254, a variable memory 256, a media reader 260, and an input output port (I/O) 262, all of which are in communication with the microprocessor 252. Program codes for directing the microprocessor 252 to carry out various functions for determining fluid level are stored in the program memory 254, which may be implemented as a random access memory (RAM) and/or a hard disk drive (HDD), or a combination thereof. For example, the program memory 254 may include instructions, e.g., program codes, for configuring the microprocessor 252 to operate as the signal processor 162 and instructions, e.g., codes, for configuring the microprocessor 252 to act as the comparator 166.
The media reader 260 facilitates loading program codes into the program memory 254 from a computer readable medium 264, such as a CD ROM disk 266, or a computer readable signal 268, such as may be received over a computer network.
The I/O 262 includes an interface 270 having an input 272 for receiving the signal representing the pump vibrations from the transducer 152. The interface 270 acts as the receiver 158 shown in Figure 2, and may comprise an analog to digital converter that converts the signal generated by the transducer 152 into a digital representation to facilitate further processing. In this embodiment, the I/O
262 further includes an interface 274 for receiving a signal representing the drive
In some implementations, the processing system 156 can be implemented as a microprocessor circuit. An example microprocessor circuit embodiment of the processing system 156 is shown in Figure 3 at 250. Referring to Figure 3, the processor circuit 250 includes a microprocessor 252, a program memory 254, a variable memory 256, a media reader 260, and an input output port (I/O) 262, all of which are in communication with the microprocessor 252. Program codes for directing the microprocessor 252 to carry out various functions for determining fluid level are stored in the program memory 254, which may be implemented as a random access memory (RAM) and/or a hard disk drive (HDD), or a combination thereof. For example, the program memory 254 may include instructions, e.g., program codes, for configuring the microprocessor 252 to operate as the signal processor 162 and instructions, e.g., codes, for configuring the microprocessor 252 to act as the comparator 166.
The media reader 260 facilitates loading program codes into the program memory 254 from a computer readable medium 264, such as a CD ROM disk 266, or a computer readable signal 268, such as may be received over a computer network.
The I/O 262 includes an interface 270 having an input 272 for receiving the signal representing the pump vibrations from the transducer 152. The interface 270 acts as the receiver 158 shown in Figure 2, and may comprise an analog to digital converter that converts the signal generated by the transducer 152 into a digital representation to facilitate further processing. In this embodiment, the I/O
262 further includes an interface 274 for receiving a signal representing the drive
-16-frequency of the drive power provided by the variable frequency drive 130. The I/O 262 further includes a first output 278 for producing the fluid level signal.
The variable memory 256 includes a plurality of storage locations including a store 280 for storing correlation data, which in this implementation corresponds to the store 164 shown in Figure 2.
In the embodiment shown in Figure 3, the signal representing pump vibrations received at the input 272 of the interface 270 is used in generating a vibration value characterizing the pump vibrations. In one embodiment generating the vibration value involves causing the microprocessor 252 to process the signal to generate amplitude values representing an amplitude of the pump vibrations and to use a correlation between pump vibrations and fluid level to generate a fluid level value corresponding to the vibration value. In another embodiment generating the vibration value involves causing the microprocessor 252 to generate frequency spectrum indicia values and to use a correlation between reference frequency spectrum indicia and fluid level values to generate the fluid level value. These embodiments are described in greater detail below.
Frequency spectrum embodiment Referring to Figure 4, a flowchart depicting an example computer-implemented process 200 for determining a fluid level is shown. The process 200 can be implemented by the processor circuit 250 shown in Figure 3, although a differently configured system can be used. For illustrative purposes, the process 200 is described in the context of the processor circuit 250. In this example, the blocks generally represent instructions that may be read from the computer readable medium 264, and stored in the program memory 254, for directing the microprocessor 252 to perform various functions related to the fluid level
The variable memory 256 includes a plurality of storage locations including a store 280 for storing correlation data, which in this implementation corresponds to the store 164 shown in Figure 2.
In the embodiment shown in Figure 3, the signal representing pump vibrations received at the input 272 of the interface 270 is used in generating a vibration value characterizing the pump vibrations. In one embodiment generating the vibration value involves causing the microprocessor 252 to process the signal to generate amplitude values representing an amplitude of the pump vibrations and to use a correlation between pump vibrations and fluid level to generate a fluid level value corresponding to the vibration value. In another embodiment generating the vibration value involves causing the microprocessor 252 to generate frequency spectrum indicia values and to use a correlation between reference frequency spectrum indicia and fluid level values to generate the fluid level value. These embodiments are described in greater detail below.
Frequency spectrum embodiment Referring to Figure 4, a flowchart depicting an example computer-implemented process 200 for determining a fluid level is shown. The process 200 can be implemented by the processor circuit 250 shown in Figure 3, although a differently configured system can be used. For illustrative purposes, the process 200 is described in the context of the processor circuit 250. In this example, the blocks generally represent instructions that may be read from the computer readable medium 264, and stored in the program memory 254, for directing the microprocessor 252 to perform various functions related to the fluid level
-17-determination. The instructions to implement each block may be written in any suitable program language, such as C, C++ and/or assembly code, for example.
Reference frequency spectrum indicia are obtained (Block 202). In this example, the reference frequency spectrum indicia are pre-determined and stored as reference indicia values in the variable memory 256 and are obtained by the microprocessor 252.
The reference frequency spectrum indicia values may be pre-determined by operating the pump 116 in the absence of the fluid 114 (i.e. under a starvation condition). Under these conditions vibrations of the pump is un-damped by fluid and will generate a first vibration frequency spectrum sref. The values stored in the store 280 may be signature values associated with the spectrum sref, such as an amplitude and a frequency of a dominant spectral component curef in the spectrum.
A signal representing a frequency spectrum Sd of the pump vibrations for the operating conditions under which it is desired to determine the fluid level is received (Block 204). In this example, the signal is received by the interface of the I/O 262 and transmitted to the microprocessor 252. When the fluid 114 surrounds any portion of the pump 116, the fluid can alter the frequency spectrum of the pump vibrations, thus causing a change in frequency spectrum from the reference frequency spectrum generated under the reference operating conditions.
A frequency spectrum indicia is generated for the spectrum Sd (Block 206), in this example by the microprocessor 252. For example, the indicia may be signature
Reference frequency spectrum indicia are obtained (Block 202). In this example, the reference frequency spectrum indicia are pre-determined and stored as reference indicia values in the variable memory 256 and are obtained by the microprocessor 252.
The reference frequency spectrum indicia values may be pre-determined by operating the pump 116 in the absence of the fluid 114 (i.e. under a starvation condition). Under these conditions vibrations of the pump is un-damped by fluid and will generate a first vibration frequency spectrum sref. The values stored in the store 280 may be signature values associated with the spectrum sref, such as an amplitude and a frequency of a dominant spectral component curef in the spectrum.
A signal representing a frequency spectrum Sd of the pump vibrations for the operating conditions under which it is desired to determine the fluid level is received (Block 204). In this example, the signal is received by the interface of the I/O 262 and transmitted to the microprocessor 252. When the fluid 114 surrounds any portion of the pump 116, the fluid can alter the frequency spectrum of the pump vibrations, thus causing a change in frequency spectrum from the reference frequency spectrum generated under the reference operating conditions.
A frequency spectrum indicia is generated for the spectrum Sd (Block 206), in this example by the microprocessor 252. For example, the indicia may be signature
-18-values associated with the spectrum Sd, such as for example an amplitude and a frequency of a dominant spectral component Wd in the spectrum sd.
A difference .6w is calculated between the frequency spectrum indicia Wref and cud (Block 208), in this example by the microprocessor 252. The difference dw is attributable to the fluid 114 in communication with the pump 116.
The fluid level L associated with the difference dw is determined (Block 210), in this example by the microprocessor 252. In one embodiment, it is assumed that the motor acts as a simple harmonic oscillator, in which case the displacement of a particle x(t) from its initial resting position is defined by the following equation derived from Newton's second law of motion:
X(I) = x,,, cos(wot+cp) (Eqn 1) where x(t) is the change in length;
x,,, is the amplitude;
wo is the undamped angular frequency of the oscillator; and cp is the phase constant.
The vibration of particles of the motor would have corresponding oscillations, these oscillations would differ in x,,,, cos (wot + gyp) variables.
When a fluid is in communication with the pump, friction between the fluid and the oscillating mass (i.e. the pump) acts to dampen the oscillation. The frictional damping force may be written as:
Fd = -bv (Eqn 2)
A difference .6w is calculated between the frequency spectrum indicia Wref and cud (Block 208), in this example by the microprocessor 252. The difference dw is attributable to the fluid 114 in communication with the pump 116.
The fluid level L associated with the difference dw is determined (Block 210), in this example by the microprocessor 252. In one embodiment, it is assumed that the motor acts as a simple harmonic oscillator, in which case the displacement of a particle x(t) from its initial resting position is defined by the following equation derived from Newton's second law of motion:
X(I) = x,,, cos(wot+cp) (Eqn 1) where x(t) is the change in length;
x,,, is the amplitude;
wo is the undamped angular frequency of the oscillator; and cp is the phase constant.
The vibration of particles of the motor would have corresponding oscillations, these oscillations would differ in x,,,, cos (wot + gyp) variables.
When a fluid is in communication with the pump, friction between the fluid and the oscillating mass (i.e. the pump) acts to dampen the oscillation. The frictional damping force may be written as:
Fd = -bv (Eqn 2)
-19-where Fd is the frictional force exerted due to the fluid resisting the vibration or oscillation;
b is the damping constant depending on the fluid constitution and the interface between the pump and the fluid; and v is the velocity into the damped fluid.
From Hook's law of elasticity, the oscillatory force is given by:
F, _ -kx (Eqn 3) where k is the spring constant. For an undamped oscillator, the natural frequency of oscillation is:
wo rk (Egn4) Combining Eqn 2 and Eqn 3, yields the net force on the body for damped oscillations:
EF = -kx - by ; (Eqn 5) which may be rewritten as:
mz= -kx - bx. (Eqn 6) Solving the differential Eqn 6 may yields:
x(t)=x,,e-h"2i cos(w1t+(P) (Eqn 7)
b is the damping constant depending on the fluid constitution and the interface between the pump and the fluid; and v is the velocity into the damped fluid.
From Hook's law of elasticity, the oscillatory force is given by:
F, _ -kx (Eqn 3) where k is the spring constant. For an undamped oscillator, the natural frequency of oscillation is:
wo rk (Egn4) Combining Eqn 2 and Eqn 3, yields the net force on the body for damped oscillations:
EF = -kx - by ; (Eqn 5) which may be rewritten as:
mz= -kx - bx. (Eqn 6) Solving the differential Eqn 6 may yields:
x(t)=x,,e-h"2i cos(w1t+(P) (Eqn 7)
-20-where Wd is the angular frequency of the oscillator as damped by the fluid 114;
and m is the mass of the oscillating particle.
The damped frequency is then given by:
O)d r k _ b2 (Eqn 8) m 4m2 The damped frequency Wd is thus dependent on the damping constant b, which is a property of the fluid 114 in communication with the pump 116. If the damping constant for the fluid 114 is known or remains constant over a period of interest, then the change in frequency dw (in this case the difference between wo and Wd) may be related to a fluid level L. In practice, it is difficult to directly determine the mass m in Eqn 7. However, a calibration of the system may be obtained by taking an independent measurement of fluid level, and relating the measured fluid level to a measured frequency difference Aw. Alternatively, the pump may be operated under a plurality of different fluid levels, which may be combined with measured frequency differences to generate a plurality of values for a look-up table or for fitting to an interpolation formula, thereby facilitating conversion of frequency differences into fluid level L.
In one implementation of the process shown in Figure 4, a starved pump is used as a reference operating condition which may be assumed to approximate the undamped natural frequency wo. When the fluid 114 is in communication with the pump 116, the level of damping provided by the fluid is dependent on the mass of the fluid surrounding the pump, which in turn is dependent on both fluid constitution and fluid level. Accordingly, to accurately determine the fluid level L,
and m is the mass of the oscillating particle.
The damped frequency is then given by:
O)d r k _ b2 (Eqn 8) m 4m2 The damped frequency Wd is thus dependent on the damping constant b, which is a property of the fluid 114 in communication with the pump 116. If the damping constant for the fluid 114 is known or remains constant over a period of interest, then the change in frequency dw (in this case the difference between wo and Wd) may be related to a fluid level L. In practice, it is difficult to directly determine the mass m in Eqn 7. However, a calibration of the system may be obtained by taking an independent measurement of fluid level, and relating the measured fluid level to a measured frequency difference Aw. Alternatively, the pump may be operated under a plurality of different fluid levels, which may be combined with measured frequency differences to generate a plurality of values for a look-up table or for fitting to an interpolation formula, thereby facilitating conversion of frequency differences into fluid level L.
In one implementation of the process shown in Figure 4, a starved pump is used as a reference operating condition which may be assumed to approximate the undamped natural frequency wo. When the fluid 114 is in communication with the pump 116, the level of damping provided by the fluid is dependent on the mass of the fluid surrounding the pump, which in turn is dependent on both fluid constitution and fluid level. Accordingly, to accurately determine the fluid level L,
-21-knowledge of constitution of the fluid or at least the density of the fluid is used.
For example, a fluid having a greater proportion of aerated froth would provide less damping, and therefore a smaller difference Aw than a fluid having little or no froth component. While the fluid constitution may change over time, such changes are expected to be small. Example of determinations of fluid density include computing a density based on a known or assumed constitution of the fluid, or performing laboratory testing of a fluid sample.
In another embodiment, the reference frequency indicia may be selected in accordance with a drive frequency fd of the electrical drive power supplied to the pump 116. For example, in embodiments where the pump 116 includes an alternating current electrical motor that receives power from a variable frequency drive (not shown), the rotational speed of the pump would depend on the drive frequency. Since pump vibrations would generally be associated with the rotation, the frequency spectrum of the pump vibrations would be expected to have a strong frequency component due to rotation that changes when the drive frequency changes. The drive frequency may thus provide useful indicia for use as a reference frequency spectrum indicia.
Amplitude embodiment In an alternative embodiment, the processing system 156 may be configured to receive and process more than one transducer. Referring to Figure 5, an embodiment is shown in which an apparatus for determining a level of the fluid 114 in the oil well 100 is shown at 350. The apparatus 350 includes a processing system 352, which may be implemented using a microprocessor circuit similar to that shown in Figure 3, with provision for receiving additional transducer signals at a plurality of inputs 366. The processing system 352 also includes an output 368 for producing a fluid level signal. In the embodiment shown the apparatus
For example, a fluid having a greater proportion of aerated froth would provide less damping, and therefore a smaller difference Aw than a fluid having little or no froth component. While the fluid constitution may change over time, such changes are expected to be small. Example of determinations of fluid density include computing a density based on a known or assumed constitution of the fluid, or performing laboratory testing of a fluid sample.
In another embodiment, the reference frequency indicia may be selected in accordance with a drive frequency fd of the electrical drive power supplied to the pump 116. For example, in embodiments where the pump 116 includes an alternating current electrical motor that receives power from a variable frequency drive (not shown), the rotational speed of the pump would depend on the drive frequency. Since pump vibrations would generally be associated with the rotation, the frequency spectrum of the pump vibrations would be expected to have a strong frequency component due to rotation that changes when the drive frequency changes. The drive frequency may thus provide useful indicia for use as a reference frequency spectrum indicia.
Amplitude embodiment In an alternative embodiment, the processing system 156 may be configured to receive and process more than one transducer. Referring to Figure 5, an embodiment is shown in which an apparatus for determining a level of the fluid 114 in the oil well 100 is shown at 350. The apparatus 350 includes a processing system 352, which may be implemented using a microprocessor circuit similar to that shown in Figure 3, with provision for receiving additional transducer signals at a plurality of inputs 366. The processing system 352 also includes an output 368 for producing a fluid level signal. In the embodiment shown the apparatus
-22-350 includes a pair of transducers 354 and 356 at the wellhead 104, and three transducers 358, 360, and 362 along the production tubing 136. Portions of the cable 128 for providing electrical drive current to the pump 116 have been omitted in Figure 5 to more clearly show the transducer locations. As an example, for an electric submersible pump 116 disposed in the borehole 102 at a depth of about 40 meters below the surface, the transducers 358, 360, and 362 may be respectively located at 5, 15, 25, and 35 meters below the surface.
In one embodiment the transducers 354 - 362 may be tri-axial accelerometers that are operable to produce signal components characterizing vibration in an x-axis direction aligned with the length of the production tubing, and y-axis and t-axis directions generally aligned in a cross sectional plane through the production tubing, as shown at 364 in Figure 5. Each transducer 354 - 362 would thus generate three signal components. Depending on the well completion and configuration of the wellhead 104, different vibration components for each respective transducer may have higher or lower amplitudes. For example, at the wellhead 104, the z-axis and y-axis components may be more attenuated by the rigidity of the wellhead structure than the same components from transducers along the production tubing 136 where less structural constraint is present.
In one embodiment, the transducers 354 - 362 are configured to produce vibration samples at a rate of about 600 samples per second, while the fluid level L in the borehole 102 would generally only vary over several minutes.
Accordingly, averaging may be applied to reduce noise in the vibration signals.
In one embodiment, the vibration samples are processed to extract root-mean-square (RMS) amplitude values. The RMS values may be further averaged over a time period (for example 30 seconds) to further reduce signal noise effects by applying a moving-window filter of to the RMS values. Additional signal
In one embodiment the transducers 354 - 362 may be tri-axial accelerometers that are operable to produce signal components characterizing vibration in an x-axis direction aligned with the length of the production tubing, and y-axis and t-axis directions generally aligned in a cross sectional plane through the production tubing, as shown at 364 in Figure 5. Each transducer 354 - 362 would thus generate three signal components. Depending on the well completion and configuration of the wellhead 104, different vibration components for each respective transducer may have higher or lower amplitudes. For example, at the wellhead 104, the z-axis and y-axis components may be more attenuated by the rigidity of the wellhead structure than the same components from transducers along the production tubing 136 where less structural constraint is present.
In one embodiment, the transducers 354 - 362 are configured to produce vibration samples at a rate of about 600 samples per second, while the fluid level L in the borehole 102 would generally only vary over several minutes.
Accordingly, averaging may be applied to reduce noise in the vibration signals.
In one embodiment, the vibration samples are processed to extract root-mean-square (RMS) amplitude values. The RMS values may be further averaged over a time period (for example 30 seconds) to further reduce signal noise effects by applying a moving-window filter of to the RMS values. Additional signal
-23-processing may be applied to remove noise or other disturbances from the vibration signals.
As described above for the frequency spectrum embodiment, a correlation between vibration values and fluid level may be generated under reference conditions for independently determined fluid levels. In this embodiment, the correlation may be saved in the store 164 as a calibration value relating vibration amplitude to fluid level, or as a set of calibration values for combining vibration amplitude component values obtained from the transducers 354 - 362 to generate a fluid level value.
As in the frequency spectrum embodiment described above, a fluid density increase between the fluid used to obtain the correlation values and the actual fluid 114 in communication with the pump 116 would cause greater attenuation of the vibration values thus providing a source of error in the generated fluid level.
Accordingly, in one embodiment where the reference vibration values are obtained for a reference fluid having a reference fluid constitution, correlating may further involve determining a constitution of the fluid 114 in communication with the pump and applying a correction to the correlation for a determined fluid constitution.
The above described embodiments result in the generation of a fluid level signal that may be displayed to an operator of the oil well 100, and/or used in other control systems as a control input. For example the well control system described above may receive the fluid level signal and generate the pump speed control signal (shown in Figure 1) based on the fluid level such that when the fluid level is too low the pump speed control signal at the input 132 of the VFD
130 causes the pump speed to be reduced allowing the fluid level to rise in the
As described above for the frequency spectrum embodiment, a correlation between vibration values and fluid level may be generated under reference conditions for independently determined fluid levels. In this embodiment, the correlation may be saved in the store 164 as a calibration value relating vibration amplitude to fluid level, or as a set of calibration values for combining vibration amplitude component values obtained from the transducers 354 - 362 to generate a fluid level value.
As in the frequency spectrum embodiment described above, a fluid density increase between the fluid used to obtain the correlation values and the actual fluid 114 in communication with the pump 116 would cause greater attenuation of the vibration values thus providing a source of error in the generated fluid level.
Accordingly, in one embodiment where the reference vibration values are obtained for a reference fluid having a reference fluid constitution, correlating may further involve determining a constitution of the fluid 114 in communication with the pump and applying a correction to the correlation for a determined fluid constitution.
The above described embodiments result in the generation of a fluid level signal that may be displayed to an operator of the oil well 100, and/or used in other control systems as a control input. For example the well control system described above may receive the fluid level signal and generate the pump speed control signal (shown in Figure 1) based on the fluid level such that when the fluid level is too low the pump speed control signal at the input 132 of the VFD
130 causes the pump speed to be reduced allowing the fluid level to rise in the
-24-borehole 102. Similarly, when the fluid level is too high, the pump speed control signal may cause the pump speed to be increased to lower the fluid level in the borehole 102. Advantageously, the fluid level is produced during operation of the pump 116, and there is thus no need to interrupt production of the well 100 to perform fluid level determinations. The disclosed embodiments are also capable of providing a continuous fluid level, thereby facilitating optimal operation of the pump 116 for extraction of produced fluids from the well 100.
In other embodiments, the downhole pump may be a reciprocating piston pump, which is coupled to an actuator for providing a reciprocating drive to the piston pump. A pumpjack is one example of such an actuator and the term is used to refer to the above-ground drive system for a reciprocating piston pump. A
pumpjack actuator may comprise a rotating electric motor or engine in combination with a mechanical coupling that converts rotary motion of the motor into a vertical reciprocating motion for driving the pump piston.
While the above embodiments have been described in relation to an oil well, the disclosed methods and apparatus may be used in pumping operations other than oil extraction and recovery. For example, the above embodiments may be adapted for use in implementations in which water is pumped out of a reservoir using an ESP or other downhole pump. While specific embodiments of the invention have been described and illustrated, such embodiments should be considered illustrative of the invention only and not as limiting the invention as construed in accordance with the accompanying claims.
In other embodiments, the downhole pump may be a reciprocating piston pump, which is coupled to an actuator for providing a reciprocating drive to the piston pump. A pumpjack is one example of such an actuator and the term is used to refer to the above-ground drive system for a reciprocating piston pump. A
pumpjack actuator may comprise a rotating electric motor or engine in combination with a mechanical coupling that converts rotary motion of the motor into a vertical reciprocating motion for driving the pump piston.
While the above embodiments have been described in relation to an oil well, the disclosed methods and apparatus may be used in pumping operations other than oil extraction and recovery. For example, the above embodiments may be adapted for use in implementations in which water is pumped out of a reservoir using an ESP or other downhole pump. While specific embodiments of the invention have been described and illustrated, such embodiments should be considered illustrative of the invention only and not as limiting the invention as construed in accordance with the accompanying claims.
Claims (44)
1. A method for determining a level of a fluid in communication with a downhole pump during a pumping operation, the method comprising:
receiving a signal representing pump vibrations generated by operation of the pump during the pumping operation;
based on the signal, generating a vibration value characterizing the pump vibrations; and using a correlation between pump vibrations and fluid level to generate a fluid level value corresponding to the vibration value.
receiving a signal representing pump vibrations generated by operation of the pump during the pumping operation;
based on the signal, generating a vibration value characterizing the pump vibrations; and using a correlation between pump vibrations and fluid level to generate a fluid level value corresponding to the vibration value.
2. The method of claim 1 wherein receiving the signal comprises receiving the signal from a vibration transducer configured to receive pump vibrations and to generate the signal representing the pump vibrations.
3. The method of claim 2 wherein the vibration transducer is coupled to a conduit that is coupled to the pump, the conduit being operable to transmit pump vibrations from the pump to the transducer.
4. The method of claim 3 wherein the vibration transducer is coupled to an electrical conduit housing an electrical cable for supplying electrical power to the pump.
5. The method of claim 3 wherein the pump includes an outlet for discharging fluid from the pump and wherein the conduit comprises production tubing extending between an outlet of the pump and a wellhead disposed at the surface, and wherein the vibration transducer is coupled to the production tubing at a location spaced apart from the outlet of the pump along the production tubing.
6. The method of claim 5 wherein the vibration transducer comprises a plurality of vibration transducers disposed at spaced apart locations along the production tubing and wherein receiving the signal comprises receiving signals from each of the vibration transducers, each signal representing pump vibrations at the respective transducer locations along the production tubing and wherein the generating the vibration values comprises combining values from the signals to generate the values characterizing the pump vibrations.
7. The method of claim 5 wherein the pump includes an inlet in communication with fluid produced from a steam assisted gravity drainage well.
8. The method of claim 1 wherein generating the vibration value comprises processing the signal to generate amplitude values representing an amplitude of the pump vibrations.
9. The method of claim 8 wherein processing the signal to generate the amplitude values comprises processing the signal to generate root mean square (RMS) amplitude values.
10. The method of claim 9 further comprising averaging the RMS amplitude values over a time period to generate an average value representing pump vibrations during the time period.
11. The method of claim 8 wherein using the correlation between pump vibrations and fluid level comprises applying a predetermined relationship between pump vibration amplitude values and fluid level values to generate the fluid level value.
12. The method of claim 1 wherein generating the vibration value comprises processing the signal to generate frequency spectrum indicia values and wherein using the correlation between pump vibrations and fluid level comprises using a predetermined correlation between reference frequency spectrum indicia and fluid level values to generate the fluid level value.
13. The method of claim 12 wherein processing the signal to generate the frequency spectrum indicia comprises determining a fundamental frequency of the pump vibrations.
14. The method of claim 13 wherein using the correlation between pump vibrations and fluid level to generate the fluid level value comprises:
determining a reference fundamental frequency of the pump vibrations under the reference fluid level conditions; and determining a difference between the fundamental vibration frequency and the fundamental vibration frequency of the pump under the reference fluid level conditions.
determining a reference fundamental frequency of the pump vibrations under the reference fluid level conditions; and determining a difference between the fundamental vibration frequency and the fundamental vibration frequency of the pump under the reference fluid level conditions.
15. The method of claim 13 wherein the pump comprises an alternating current motor coupled to a variable frequency drive for providing drive power to the motor and wherein generating the fluid level value comprises determining a frequency offset between the fundamental frequency of the pump vibrations and a frequency of the drive power supplied to the motor.
16. The method of claim 13 wherein the pump comprises a reciprocating piston pump coupled to an actuator operable to provide a reciprocating drive for driving the pump and wherein generating the fluid level value comprises determining a frequency offset between the fundamental frequency of the pump vibrations and an operating frequency associated with the actuator.
17. The method of claim 1 further comprising generating the correlation between pump vibrations and fluid level.
18. The method of claim 17 wherein generating the correlation comprises obtaining reference vibration values associated with operating the pump under reference fluid level conditions.
19. The method of claim 18 wherein obtaining reference vibration values comprises:
determining the reference fluid level by performing a fluid level measurement that is independent of pump vibration;
receiving a reference signal representing pump vibration under the reference pump operating conditions; and generating the reference vibration values based on the reference signal.
determining the reference fluid level by performing a fluid level measurement that is independent of pump vibration;
receiving a reference signal representing pump vibration under the reference pump operating conditions; and generating the reference vibration values based on the reference signal.
20. The method of claim 18 wherein obtaining reference vibration values comprises obtaining reference vibration amplitude values.
21. The method of claim 18 wherein obtaining reference vibration values comprises obtaining reference frequency spectrum indicia values.
22. The method of claim 18 wherein obtaining the reference vibration values comprises obtaining reference vibration values associated with operating the pump in communication with a reference fluid having reference fluid constitution and wherein using the correlation comprises:
determining a constitution of the fluid in communication with the pump; and applying a correction to the correlation for a fluid of the determined constitution.
determining a constitution of the fluid in communication with the pump; and applying a correction to the correlation for a fluid of the determined constitution.
23. An apparatus for determining a level of a fluid in communication with a downhole pump during a pumping operation, the apparatus comprising:
a receiver operably configured to receive a signal representing pump vibrations generated by operation of the pump during the pumping operation;
a signal processor operably configured to generate a vibration value characterizing the pump vibrations based on the signal; and a comparator operably configured to use a correlation between pump vibrations and fluid level to generate a fluid level value corresponding to the vibration value.
a receiver operably configured to receive a signal representing pump vibrations generated by operation of the pump during the pumping operation;
a signal processor operably configured to generate a vibration value characterizing the pump vibrations based on the signal; and a comparator operably configured to use a correlation between pump vibrations and fluid level to generate a fluid level value corresponding to the vibration value.
24. The apparatus of claim 23 further comprising a vibration transducer configured to receive pump vibrations and to generate the signal representing the pump vibrations.
25. The apparatus of claim 24 wherein the vibration transducer is coupled to a conduit that is coupled to the pump, the conduit being operable to transmit pump vibrations from the pump to the transducer.
26. The apparatus of claim 25 wherein the vibration transducer is coupled to an electrical conduit housing an electrical cable for supplying electrical power to the pump.
27. The apparatus of claim 25 wherein the pump comprises an outlet for discharging fluid from the pump and wherein the conduit comprises production tubing extending between an outlet of the pump and a wellhead disposed at the surface, and wherein the vibration transducer is coupled to the production tubing at a location spaced apart from the outlet of the pump along the production tubing.
28. The apparatus of claim 27 wherein the vibration transducer comprises a plurality of vibration transducers disposed at spaced apart locations along the production tubing and operably configured to generate respective signals, each signal representing pump vibrations at the respective transducer locations along the production tubing and wherein the signal processor is operably configured to generate the vibration value by combining values from the signals to generate the values characterizing the pump vibrations.
29. The apparatus of claim 27 wherein the pump comprises an inlet in communication with fluid produced from a steam assisted gravity drainage well.
30. The apparatus of claim 23 wherein the signal processor is operably configured generate the vibration value by processing the signal to generate amplitude values representing an amplitude of the pump vibrations.
31. The apparatus of claim 30 wherein the signal processor is operably configured to process the signal to generate root mean square (RMS) amplitude values.
32. The apparatus of claim 31 wherein the signal processor is operably configured to average the RMS amplitude values over a time period to generate an average value representing pump vibrations during the time period.
33. The apparatus of claim 30 wherein the comparator is operably configured to apply a predetermined relationship between pump vibration amplitude values and fluid level values to generate the fluid level value.
34. The apparatus of claim 23 wherein the signal processor is operably configured to generate the vibration value by processing the signal to generate frequency spectrum indicia values and wherein the comparator is operably configured to use a predetermined correlation between reference frequency spectrum indicia and fluid level values to generate the fluid level value.
35. The apparatus of claim 34 wherein the signal processor is operably configured to process the signal to generate the frequency spectrum indicia by determining a fundamental frequency of the pump vibrations.
36. The apparatus of claim 35 wherein the comparator is operably configured to:
determine a reference fundamental frequency of the pump vibrations under the reference fluid level conditions; and determine a difference between the fundamental vibration frequency and the fundamental vibration frequency of the pump under the reference fluid level conditions.
determine a reference fundamental frequency of the pump vibrations under the reference fluid level conditions; and determine a difference between the fundamental vibration frequency and the fundamental vibration frequency of the pump under the reference fluid level conditions.
37. The apparatus of claim 35 wherein the pump comprises an alternating current motor coupled to a variable frequency drive for providing drive power to the motor and wherein the comparator is operably configured to generate the fluid level value by determining a frequency offset between the fundamental frequency of the pump vibrations and a frequency of the drive power supplied to the motor.
38. The apparatus of claim 35 wherein the pump comprises a reciprocating piston pump coupled to an actuator operable to provide a reciprocating drive for driving the pump and wherein the comparator is operably configured to generate the fluid level value by determining a frequency offset between the fundamental frequency of the pump vibrations and an operating frequency associated with the actuator.
39. The apparatus of claim 23 further comprising a processing system operably configured to generate the correlation between pump vibrations and fluid level.
40. The apparatus of claim 39 wherein the processing system is operably configured to generate the correlation by obtaining reference vibration values associated with operating the pump under reference fluid level conditions.
41. The apparatus of claim 40 wherein the processing system is operably configured to obtain reference vibration values by:
determining the reference fluid level by performing a fluid level measurement that is independent of pump vibration;
receiving a reference signal representing pump vibration under the reference pump operating conditions; and generating the reference vibration values based on the reference signal.
determining the reference fluid level by performing a fluid level measurement that is independent of pump vibration;
receiving a reference signal representing pump vibration under the reference pump operating conditions; and generating the reference vibration values based on the reference signal.
42. The apparatus of claim 40 wherein the processing system is operably configured to obtain reference vibration amplitude values.
43. The apparatus of claim 40 wherein the processing system is operably configured to obtain reference frequency spectrum indicia values.
44. The apparatus of claim 40 wherein the processing system is operably configured to obtain reference vibration values associated with operating the pump in communication with a reference fluid having reference fluid constitution and wherein the processing system is further operably configured to:
determine a constitution of the fluid in communication with the pump; and apply a correction to the correlation for a fluid of the determined constitution.
determine a constitution of the fluid in communication with the pump; and apply a correction to the correlation for a fluid of the determined constitution.
Applications Claiming Priority (3)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US41476010P | 2010-11-17 | 2010-11-17 | |
| US61/414,760 | 2010-11-17 | ||
| PCT/CA2011/001277 WO2012065257A1 (en) | 2010-11-17 | 2011-11-17 | Method and apparatus for determining a level of a fluid in communication with a downhole pump |
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| Publication Number | Publication Date |
|---|---|
| CA2762269A1 CA2762269A1 (en) | 2012-05-17 |
| CA2762269C true CA2762269C (en) | 2014-01-21 |
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| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2762269A Active CA2762269C (en) | 2010-11-17 | 2011-11-17 | Method and apparatus for determining a level of a fluid in communication with a downhole pump |
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| Country | Link |
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| CA (1) | CA2762269C (en) |
| WO (1) | WO2012065257A1 (en) |
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| Publication number | Priority date | Publication date | Assignee | Title |
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| RU2494248C1 (en) * | 2012-10-19 | 2013-09-27 | Открытое акционерное общество "Татнефть" им. В.Д. Шашина | Method for determining liquid level in oil well with high temperature for extraction of high-viscosity oil |
| WO2015053784A1 (en) * | 2013-10-11 | 2015-04-16 | Halliburton Energy Services, Inc. | Estimation of formation properties by analyzing response to pressure changes in a wellbore |
| US9938805B2 (en) | 2014-01-31 | 2018-04-10 | Mts Systems Corporation | Method for monitoring and optimizing the performance of a well pumping system |
| CN111344474A (en) * | 2017-11-02 | 2020-06-26 | Qed环境***有限责任公司 | Liquid level sensor system |
| CN110500070A (en) * | 2019-08-23 | 2019-11-26 | 中国石油天然气股份有限公司 | A kind of continuous pipe water sampling device of preset cable flexible compound and method |
| RU2731777C1 (en) * | 2020-02-28 | 2020-09-08 | Публичное акционерное общество «Татнефть» имени В.Д. Шашина | Method of determining temperature distribution in an oil well which produces super-viscous oil |
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| Publication number | Priority date | Publication date | Assignee | Title |
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| US4390321A (en) * | 1980-10-14 | 1983-06-28 | American Davidson, Inc. | Control apparatus and method for an oil-well pump assembly |
| CA2242505A1 (en) * | 1997-09-02 | 1999-03-02 | Eric Lee Berger | Method and apparatus for enhancing pump-off controller performance |
| US7668694B2 (en) * | 2002-11-26 | 2010-02-23 | Unico, Inc. | Determination and control of wellbore fluid level, output flow, and desired pump operating speed, using a control system for a centrifugal pump disposed within the wellbore |
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| CA2762269A1 (en) | 2012-05-17 |
| WO2012065257A1 (en) | 2012-05-24 |
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