Modular electro-optic flowmeter system for downhole
A modular sensor system using electro acoustic technology to measure downhole properties, such as flow rate, density and fluid fraction of oil in a production string, is described. Modular sensor assemblies inside a wellbore collect various local fluid parameters at each location. The local fluid parameters are combined to determine the downhole properties.
1. A system comprising:
flow meter assemblies located between casing collars in a downhole production string; each flow meter comprising;
an electro acoustic technology sensor assembly mounted on the outside of a section of production casing in close proximity to a fiber optic cable that is part of a fiber optic distributed acoustic sensing (DAS) system connected to a surface distributed acoustic sensing interrogator;
a vortex energy harvester and velocity sensor on the inside of the section of production casing and located within a recess in a fixture attached to the collar of the section of the production casing;
pressure and temperature sensors in the fixture attached to the collar of the section of the production casing; and
a piezo electric transmitter in the electro acoustic technology sensor to transfer pressure, temperature, and velocity data to the fiber optic cable.
2. The system of claim 1 wherein the electro acoustic technology sensor comprises a piezo electric transmitter to transfer pressure, temperature, and velocity data to the fiber optic cable.
3. The system of claim 2 wherein the vortex energy harvester powers the electro acoustic technology sensor assembly.
4. The system of claim 2 wherein the vortex energy harvester and velocity sensor is a velocity sensor in which a frequency of vibration can be used to determine the velocity of the fluid in the casing.
5. The system of claim 1 wherein the electro acoustic technology sensor assembly comprises an internal rechargeable battery.
6. The system of claim 5 wherein the vortex energy harvester charges the internal rechargeable battery.
7. A method comprising:
providing flow meter assemblies located between casing collars in a downhole production string; each flow meter providing:
an electro acoustic technology sensor assembly mounted on the outside of a section of production casing in close proximity to a fiber optic cable that is part of a fiber optic distributed acoustic sensing (DAS) system connected to a surface distributed acoustic sensing interrogator;
a vortex energy harvester and velocity sensor on the inside of the section of production casing and located within a recess in a fixture attached to the collar of the section of the production casing;
pressure and temperature sensors in the fixture attached to the collar of the section of the production casing; and
a transmitter in the electro acoustic technology sensor to transfer acoustic perturbations representing the pressure, temperature, and velocity data to the fiber optic cable;
receiving and optically transferring the pressure, temperature, and velocity data perturbations measured by each of the flow meter assemblies through the fiber optic cable to the surface distributed acoustic sensing interrogator; and
determining, from measured parameters, flow rate, density and oil-gas-water fraction from each zone.
8. The method of claim 7 wherein the transmitter in the electro acoustic technology sensor utilizes a piezo electric element.
9. The method of claim 7 wherein an established method of calculation comprises utilizing distributed acoustic sensing (DAS) with temperature and pressure data to determine a flow regime along a wellbore.
10. The method of claim 7 wherein an established method of calculation comprises estimating gas fraction by measuring an acoustic velocity in a fluid in the casing using distributed acoustic sensing (DAS) in combination with noise measurements downhole.
11. The method of claim 10 wherein active noise transmitters generate the noise measurements.
12. The method of claim 10 further comprising using the distributed acoustic sensing (DAS) system to track acoustic pulses transmitted from acoustic transmitters.
13. The method of claim 7 wherein an established method of calculation comprises utilizing alternate vortex harvester and velocity sensors as acoustic transmitters and acoustic sensors so that a pair of the vortex harvester and velocity sensors can measure gas fractions between the pair.
14. The method of claim 13 further comprising using a Doppler shift between alternate vortex harvester and velocity sensors to measure bulk volumetric flows.
15. The method of claim 7 wherein the vortex energy harvester provides a charge to an internal battery in the electro acoustic technology sensor assembly.
16. The method of claim 7 wherein the vortex energy harvester powers the electro acoustic technology sensor assembly.
17. The method of claim 7 wherein the vortex energy harvester and velocity sensor utilizes a frequency of vibration of the vortex energy harvester to determine the velocity of a flow within the casing.