1. Field of the Invention
The present invention relates to electrical submersible pumps. More specifically, the invention relates a flow meter used in conjunction with an electrical submersible pump.
2. Description of the Related Art
In hydrocarbon developments, it is common practice to use electric submersible pumping systems (ESPs) as a primary form of artificial lift. ESPs often use downhole monitoring tools to supply both temperature and pressure readings from different locations on the ESP. For example, intake pressure, discharge pressure, and motor temperature, as well as other readings may be taken on the ESP.
If wells are producing below bubble point pressure, the liberated gas, at the surface, may not allow the surface meters to provide accurate flow rates. To replace the surface single phase meters with multi-phase meters can cost tens of thousands of dollars per well. Downhole at the ESP all wells are producing with intake pressures well above the bubble point pressure. Therefore, being able to measure flow rate down hole at the ESP would allow for an accurate flow meter that will assist immensely in extending the life of the ESPs. Therefore, a low cost and accurate flow meter that will assist immensely in extending the life of the ESPs that incorporates these theories would be desirable.
Embodiments of the current application provide a method and apparatus for addressing the shortcomings of the current art, as discussed above.
By adding a pressure sensing means to existing ESP monitoring tools a reliable cost affective single phase flow meter is obtained. This invention expands the capability of ESP monitoring tools by adding single phase oil-water flow meter capability through the addition of sensors below the ESP. Just as the ESP monitoring tool sensor data is now transmitted by the existing ESP cable, the flow meter will be able to do the same with communication on power. This will provide the capability of monitoring real time flow rates to improve the operational performance of the ESPs. The cost of adding a means for measuring flow rate downhole would be substantially absorbed by the already existing need for an ESP pressure or temperature sensor and the ESP power cable which will also be used to transmit the flow meter data, in real time to surface.
The flow meter of the current application is simple in design, has no moving parts and can utilize existing ESP monitoring tool and power cable for data transmission. Application of embodiments of the current application allows for a cost effective means of providing valuable information for improving the life of the ESP.
An apparatus for metering fluid in a subterranean well includes an electric submersible pump comprising a motor, a seal section and a pump assembly and a metering assembly. The metering assembly includes an upper pipe section with an outer diameter, the upper pipe section having an upper pressure sensing means and a lower pipe section with an outer diameter smaller than the outer diameter of the upper pipe section, the lower pipe section having a lower pressure sensing means. A power cable in electronic communication with the electric submersible pump and with the metering assembly.
The metering assembly may be located either above or below the electric submersible pump. The power cable may be connected to the motor and operable to transmit data from pressure sensors. A tapered pipe section may be located between the upper pipe section and the lower pipe section, to create a smooth transition between the upper pipe section and the lower pipe section. The upper and lower pressure sensing means may either have two flow pressure sensors or it may be a single pressure differential sensor.
In an alternative embodiment, a method for metering fluid in a subterranean well include the steps of installing an electric submersible pump in a subterranean well, the electric submersible pump comprising a motor, a seal section and a pump assembly and connecting a metering to the electric submersible pump, the metering assembly comprising an upper pipe section with an outer diameter, the upper pipe section comprising an upper pressure sensing means, and a lower pipe section with an outer diameter smaller than the outer diameter of the upper pipe section, the lower pipe section comprising a lower pressure sensing means. A power cable is installed in the subterranean well, the power cable being in electronic communication with the motor and with the metering assembly.
The metering assembly may be connected to the bottom or the top of the electric submersible pump. When it is connected to the top, the pressure sensing means may collect data from fluid flowing inside of the upper and lower pipe sections. When the metering assembly is connected to the bottom of the electric submersible pump, the pressure sensing means may collect data from fluid flowing exterior to the upper and lower pipe sections. Data from the pressure sensors may be transmitted to the surface.
In one embodiment, a production water cut and fluid density may be calculated with data transmitted from the lower pressure sensing means after determining a pressure differential at the lower pressure sensing means. In this embodiment, the fluid flow rate may be calculated with data transmitted from the upper pressure sensing means after determining a pressure differential at the upper pressure sensing means. In an alternative embodiment, a production water cut and fluid density may be calculated with data transmitted from the upper pressure sensing means after determining a pressure differential at the upper pressure sensing means. In the alternative embodiment, the fluid flow rate may be calculated with data transmitted from the lower pressure sensing means after determining a pressure differential at the lower pressure sensing means.
So that the manner in which the above-recited features, aspects and advantages of the invention, as well as others that will become apparent, are attained and can be understood in detail, a more particular description of the invention briefly summarized above may be had by reference to the embodiments thereof that are illustrated in the drawings that form a part of this specification. It is to be noted, however, that the appended drawings illustrate only preferred embodiments of the invention and are, therefore, not to be considered limiting of the invention's scope, for the invention may admit to other equally effective embodiments.
In the embodiment of
Below the ESP 12 is a metering assembly 34. Metering assembly 34 comprises an upper pipe section 36 which is attached to the bottom the monitoring tool 22 of ESP 12. In alternative embodiments, monitoring tool 22 may not be a part of ESP 12 and metering assembly 34 would be attached directly to the bottom of motor 16. Upper pipe section 36 has an external diameter 38. Metering assembly 34 also comprises a lower pipe section 40, which is located below upper pipe section 36. Lower pipe section 40 has an external diameter 42 which is smaller than the external diameter 38 of upper pipe section 36. A tapered intermediate pipe section 44 mates the upper pipe section 36 to lower pipe section 40. The intermediate pipe section 44 is tapered in such a manner to create a smooth transition between upper pipe section 36 to lower pipe section 40 to minimize the sudden flow disturbance and pressure losses within bore 11.
As an example, each of upper pipe section 36 and lower pipe section 40 may have a length of 15 to 20 feet. For a metering assembly 34 deployed inside a well 10 with an internal diameter of 7 inches, which may be, for example, the internal diameter of the casing completion, the external diameter 42 of lower pipe section 40 may be 3.5 inches or smaller and the external diameter 38 of upper pipe section 36 my be 5.5 inches. As a second example, for a metering assembly 34 deployed inside a well 10 with an internal diameter of 9⅝ inches, which may be, for example, the internal diameter of the casing completion, the external diameter 42 of lower pipe section 40 may be 4.5 inches or smaller and the external diameter 38 of upper pipe section 36 my be 7 inches.
As described, the external diameters 38, 42 of upper and lower pipe sections 36, 40 are smaller than the internal diameter 13 of the bore 11 of well 10. The annular spaces between external diameters 38, 42 and bore 11 create an annular flow path 46 for the passage of fluids within the well as the fluids are drawn upwards towards fluid inlets 24 of pump assembly 20. A pressure sensing means is located on upper pipe section 36 and lower pipe section 40. The upper pressure sensing means may comprise two upper flow pressure sensors 48, 50 located on upper pipe section 36. The upper sensors 48, 50 are located at an upper distance 52 apart from each other and are capable of collecting data from fluid flowing exterior to the upper and lower pipe sections 36, 40 in the annular flow path 46. Upper distance 52 may be, for example, 10 to 15 feet. Alternatively, an upper pressure differential sensor 53 may be used to measure the pressure difference between the two upper locations. A pressure sensing means is located on upper pipe section 36 and lower pipe section 40. The lower pressure sensing means may comprise two lower flow pressure sensors 54, 56 located on lower pipe section 40. The lower sensors 54, 56 are located at a lower distance 58 apart from each other. Lower distance 58 may be, for example, 10 to 15 feet. Alternatively, a lower pressure differential sensor 59 may be used to measure the pressure difference between the two lower locations.
Because of the differences in the outer diameter 38 of upper pipe section of upper pipe section 36 and outer diameter 42 of lower pipe section 40, two distinctive flow regimes are created along the annulus flow path 46, one along lower distance 58 and another along upper distance 52. A first pressure loss may be measured over lower distance 58. The first pressure loss is determined by measuring a pressure with first lower senor 56 and second lower sensor 54 and finding the difference between the two pressure readings. Alternatively, a single pressure differential sensor may measure the first pressure loss. Because of the relatively smaller external diameter 42 of lower pipe section 40, the first pressure loss is dominated by gravitational losses.
A second pressure loss may be measured over upper distance 52. The second pressure loss is determined by measuring a pressure with first upper senor 50 and second upper sensor 48 and finding the difference between the two pressure readings. Alternatively, a single pressure differential sensor may measure the second pressure loss. Because of the relatively larger external diameter 38 of upper pipe section 36, the second pressure loss is affected by both gravitational loss and frictional loss. The pressure loss data collected by sensors 48, 50, 54, and 56 are transmitted to surface by way of the power cable 26, which is in electrical communication with the metering assembly 34. The flow rate of the fluids within well 10 and the water cut of such fluids can be calculated with this pressure loss data using hydraulic equations as further describe herein. More specifically, the first pressure loss, calculated with data from the first lower senor 56 and second lower sensor 54, or with a single pressure differential sensor, can be used to calculate oil-water mixture density and the production water cut and the second pressure loss, calculated with data from first upper senor 50 and second upper sensor 48, or with a single pressure differential sensor, can be used to calculate oil-water mixture flowrate.
In the alternative embodiment of
Metering assembly 34 with upper pipe section 36 and lower pipe section 40, are located above ESP 12, with lower pipe section 40 being connected to pump assembly 20. Lower pipe section 40 has an external diameter 42 which is smaller than the external diameter 38 of upper pipe section 36. A tapered intermediate pipe section 44 mates the upper pipe section 36 to lower pipe section 40. The intermediate pipe section 44 is tapered in such a manner to create a smooth transition between upper pipe section 36 to lower pipe section 40 to minimize the sudden flow disturbance and pressure losses within bore 11.
As an example, each of upper pipe section 36 and lower pipe section 40 may have a length of 15 to 20 feet. For a metering assembly 34 deployed inside a well 10 with an internal diameter of 7 inches, which may be, for example, the internal diameter of the casing completion, the external diameter 42 of lower pipe section 40 may be 3.5 inches or smaller and the external diameter 38 of upper pipe section 36 my be 5.5 inches. As a second example, for a metering assembly 34 deployed inside a well 10 with an internal diameter of 9⅝ inches, which may be, for example, the internal diameter of the casing completion, the external diameter 42 of lower pipe section 40 may be 4.5 inches or smaller and the external diameter 38 of upper pipe section 36 my be 7 inches.
As described, the external diameters 38, 42 of upper and lower pipe sections 36, 40 are smaller than the internal diameter 13 of the bore 11 of well 10. A packer 60 is sealingly engaged between upper pipe section 36 and the bore 11. Packer 60 seals flow path 46 so that fluids cannot travel further upwards within the wellbore 11 and instead are transported to the surface through tubing 14.
A pressure sensing means is located on upper pipe section 36 and lower pipe section 40. The upper pressure sensing means may comprise two upper flow pressure sensors 48, 50 are located on upper pipe section 36. The upper sensors 48, 50 are located at an upper distance 52 apart from each other. Upper distance 52 may be, for example, 10 to 15 feet. Alternatively, a single pressure differential sensor may be used to measure the pressure difference between the two upper locations. The lower pressure sensing means may comprise two lower flow pressure sensors 54, 56 located on lower pipe section 40. The lower sensors 54, 56 are located at a lower distance 58 apart from each other. Lower distance 58 may be, for example, 10 to 15 feet. Alternatively, a single pressure differential sensor may be used to measure the pressure difference between the two lower locations. The sensor means of
Because of the differences in the outer diameter 38 of upper pipe section of upper pipe section 36 and outer diameter 42 of lower pipe section 40, two distinctive flow regimes are created, one along lower distance 58 and another along upper distance 52. A first pressure loss may be measured over lower distance 58. The first pressure loss is determined by measuring a pressure with first lower senor 56 and second lower sensor 54 and finding the difference between the two pressure readings. Alternatively, a single pressure differential sensor can measure the first pressure loss. Because of the relatively smaller external diameter 42 of lower pipe section 40, the first pressure loss is dominated by both gravitational and friction losses.
A second pressure loss may be measured over upper distance 52. The second pressure loss is determined by measuring a pressure with first upper senor 50 and second upper sensor 48 and finding the difference between the two pressure readings. Alternatively, a single pressure differential sensor can measure the second pressure loss. Because of the relatively larger external diameter 38 of upper pipe section 36 and lower flow velocity in this region, the second pressure loss is affected only by gravitational loss.
The pressure loss data collected by sensors 48, 50, 54, and 56 are transmitted to surface by way of the power cable 26 (
In the embodiment of
Where g is the gravitational acceleration, 32.2 ft/sec2, gc is a unit conversion factor, 32.2 lbm-ft/lbf-sec2, and ρm is the oil-water mixture density in lbm/ft3. After determining ρm from eq. 1, production water cut can be calculated. A similar analysis could be performed over upper distance 52 of the embodiment of
Returning the embodiment of
Where vm is the oil-water mixture velocity in ft/sec in upper distance 52, Dh is the hydraulic diameter for the annulus in inches, calculated as internal diameter 13 minus external diameter 38. f is the friction factor. A similar analysis would also apply to the lower distance 58 of the embodiment of
The friction factor is a function of Reynolds number and roughness, and can be determined from Moody's chart or empirical correlations. Eq. 2 can be used iteratively to obtain the mixture velocity and the total oil-water flowrate. With water cut calculated previously, the individual oil and water rates can be easily calculated.
Although the present invention has been described in detail, it should be understood that various changes, substitutions, and alterations can be made hereupon without departing from the principle and scope of the invention. Accordingly, the scope of the present invention should be determined by the following claims and their appropriate legal equivalents.
The singular forms “a”, “an” and “the” include plural referents, unless the context clearly dictates otherwise. Optional or optionally means that the subsequently described event or circumstances may or may not occur. The description includes instances where the event or circumstance occurs and instances where it does not occur. Ranges may be expressed herein as from about one particular value, and/or to about another particular value. When such a range is expressed, it is to be understood that another embodiment is from the one particular value and/or to the other particular value, along with all combinations within said range.
Throughout this application, where patents or publications are referenced, the disclosures of these references in their entireties are intended to be incorporated by reference into this application, in order to more fully describe the state of the art to which the invention pertains, except when these reference contradict the statements made herein.
This application claims priority to provisional application 61/540,639 filed Sep. 29, 2011.
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