System and method for monitoring fluid flow in a wellbore using acoustic telemetry

• US 9,863,222 B2
• Filed: 10/07/2015
• Issued: 01/09/2018
• Est. Priority Date: 01/19/2015
• Status: Active Grant

• Current Assignee: Exxonmobil Upstream Research Company (Exxon Mobil Corporation)
• Original Assignee: Exxonmobil Upstream Research Company (Exxon Mobil Corporation)
• Inventors: Morrow, Timothy I., Romer, Michael C., Disko, Mark M.
• Primary Examiner(s): Alizada, Omeed
• Application Number:
  US14/876,935
• Publication Number:
  US 20160208605A1
• Time in Patent Office: 825 Days
• CPC Class Codes: E21B 43/122 Gas lift
• CPC Class Codes: E21B 47/113 using electrical indications; using light radiations
• CPC Class Codes: E21B 47/14 using acoustic waves

Abstract

An electro-acoustic system for downhole telemetry is provided herein. The system employs a series of communications nodes spaced along a string of production tubing within a wellbore. The nodes allow for wireless communication between transceivers residing within the communications nodes and a receiver at the surface. More specifically, the transceivers provide for node-to-node communication up a wellbore at high data transmission rates for data indicative of fluid flow within the production tubing adjacent gas lift valves. A method of monitoring the flow of fluid gas lift valves is also provided herein. The method uses a plurality of data transmission nodes situated along the production tubing which send signals to a receiver at the surface. The signals are then analyzed to determine gas lift valve operation and fluid flow data.

Claims

1. An electro-acoustic telemetry system for monitoring fluid flow in a wellbore, the wellbore penetrating into a subsurface formation, and the telemetry system comprising:

a production tubing disposed in the wellbore, the production tubing being comprised of threadedly-connected pipe joints;

one or more gas lift valves placed along the production tubing;

at least one sensor disposed along the production tubing adjacent each of the one or more gas lift valves, each sensor designed to measure a parameter indicative of fluid flow within the production tubing adjacent the one or more gas lift valves;

one or more sensor communications nodes associated with and in electrical communication with one of the at least one sensors and configured to receive signals from the associated sensor indicative of fluid flow;

a topside communications node placed along the wellbore proximate a surface;

a plurality of intermediate communications nodes spaced along the wellbore and attached to a pipe string, the intermediate communications nodes including a transceiver in acoustic contact with the production tubing and configured to transmit acoustic waves from node-to-node along the wellbore using the production tubing as a transmission medium for the acoustic waves from the one or more sensor communications nodes to the topside communications node; and

wherein each of the intermediate communications nodes comprises;

a sealed housing;

an electro-acoustic transducer and associated transceiver residing within the housing, with the transceiver being designed to relay signals from node-to-node up the wellbore, with each signal representing a packet of information that comprises an acoustic waveform representing fluid flow data; and

an independent power source residing within the housing providing power to the transceiver.

2. The electro-acoustic telemetry system of claim 1, wherein the surface is an earth surface, or a production platform offshore.

3. The electro-acoustic telemetry system of claim 2, wherein:

the one or more sensors for measuring a parameter indicative of fluid flow are any of;

(i) fluid velocity measurement devices residing inside of the production tubing;

(ii) temperature sensors that measure temperature of fluids flowing inside of the production tubing;

(iii) pressure sensors that measure pressure inside of the production tubing, or pressure drop across a gas lift valve;

(iv) fluid density sensors that measure the density of fluids inside of the production tubing;

(v) microphones that provide passive acoustic monitoring to listen for the sound of gas entry into the production tubing or the opening and closing of the gas lift valve;

(vi) ultrasound sensors that correlate changes in gas transmission with gas flows, bubbles, solids and other properties of flow along gas inlets;

(vii) Doppler shift sensors;

(viii) chemical sensors;

(ix) an imaging device; and

(x) combinations thereof; and

each of the one or more sensor communications nodes is configured to receive signals from the associated sensor, and relay acoustic signals indicative of readings taken by the sensors.

4. The electro-acoustic telemetry system of claim 3, wherein:

the one or more gas lift valves comprises at least two gas lift valves;

the packet of information in each signal relayed by the transceivers further comprises an identifier for the sensor communications node that originally transmitted the signal; and

the system further comprises a receiver at the surface configured to receive signals from the topside communications node.

5. The electro-acoustic telemetry system of claim 4, wherein:

the wellbore comprises a production packer sealing an annulus between the production tubing and a surrounding string of casing;

each of the at least two gas lift valves resides above the production packer; and

the pipe string is the string of production tubing.

6. The electro-acoustic telemetry system of claim 5, wherein the intermediate communications nodes are spaced apart such that each intermediate communications node resides on its own joint of production tubing.

7. The electro-acoustic telemetry system of claim 4, wherein:

the intermediate communications nodes are spaced at about 10 to 1,000 foot (3.0 to 304.8 meter) intervals; and

the transceivers transmit data in acoustic form at a rate exceeding about 50 bps.

8. The electro-acoustic telemetry system of claim 4, wherein each of the transceivers is designed to receive acoustic waves at a first frequency, and then transmit the acoustic waves at a second different frequency up the wellbore to a next communications node.

9. The electro-acoustic system of claim 4, wherein a frequency band for the acoustic wave transmission by the transceivers is about 25 KHz wide.

10. The electro-acoustic system of claim 4, wherein a frequency band for the acoustic wave transmission by the transceivers operates from about 100 kHz to 125 kHz.

11. The electro-acoustic telemetry system of claim 4, wherein the acoustic waves provide data that is modulated by (i) a multiple frequency shift keying method, (ii) a frequency shift keying method, (iii) a multi-frequency signaling method, (iv) a phase shift keying method, (v) a pulse position modulation method, or (vi) an on-off keying method.

12. The electro-acoustic system of claim 4, wherein:

each of the one or more sensors resides within the housing of its associated sensor communications node; and

an electro-acoustic transducer within the associated sensor communications node converts signals from the sensor into acoustic signals for the associated transceiver.

13. The electro-acoustic system of claim 4, wherein:

each of the one or more sensors resides adjacent but external to the housing of an associated sensor communications node; and

the electro-acoustic transducer within the associated sensor communications node converts signals from the sensor into acoustic signals for the associated transceiver.

14. The electro-acoustic telemetry system of claim 1, wherein:

a well head is placed above the wellbore; and

the topside communications node is placed (i) on an outer surface of the well head, or (ii) on the outer surface of an uppermost joint of the production tubing.

15. The electro-acoustic telemetry system of claim 1, wherein the intermediate communications nodes are attached to an outer wall of the production tubing by (i) an adhesive material, (ii) by welding, or (iii) by one or more mechanical fasteners.

16. The electro-acoustic telemetry system of claim 1, wherein:

each of the intermediate communications nodes is attached to the production tubing by one or more clamps; and

each of the one or more clamps comprises;

a first arcuate section;

a second arcuate section;

a hinge for pivotally connecting the first and second arcuate sections; and

a fastening mechanism for securing the first and second arcuate sections around an outer surface of a joint of the production tubing.

17. The electro-acoustic telemetry system of claim 4, wherein each of the sensor communications nodes also comprises an electro-acoustic transducer and associated transceiver residing within a housing, with the transceiver being designed to relay signals from node-to-node up the wellbore representing the fluid flow data.

18. The electro-acoustic telemetry system of claim 4, wherein at least one intermediate communications node resides between adjacent sensor communications nodes.

19. The electro-acoustic telemetry system of claim 4, wherein each of the at least two gas lift valves resides in a side pocket mandrel.

20. The electro-acoustic telemetry system of claim 4, wherein each of the sensors and associated sensor communications nodes resides below or within a corresponding side pocket mandrel.

21. The electro-acoustic telemetry system of claim 17, wherein the transceiver in each sensor communications node is configured to send its acoustic signals indicative of fluid flow data (i) according to a pre-programmed schedule, (ii) in the event that a condition of gas lift valve failure is identified, or (iii) only when interrogated by a user at the surface.

22. A method of monitoring fluid flow along a wellbore, the wellbore penetrating into a subsurface formation, and the method comprising:

running joints of production tubing into the wellbore to form a pipe string;

placing one or more gas lift valves along the pipe string;

placing at least one sensor along the pipe string adjacent each of the one or more gas lift valves, each sensor designed to measure a parameter indicative of fluid flow within the wellbore;

attaching a sensor communications node to the pipe string adjacent each gas lift valve, each sensor communications node being in electrical communication with an associated sensor and configured to receive signals from the associated sensor indicative of fluid flow;

attaching a topside communications node to the pipe string proximate a surface of the wellbore; and

attaching a series of intermediate communications nodes to the pipe string according to a pre-designated spacing, the intermediate communications nodes in electrical communication with one of the at least one sensors configured to acoustically transmit acoustic waves from the sensor communications nodes to the topside communications node; and

wherein each of the intermediate communications nodes comprises;

a sealed housing;

an electro-acoustic transducer and associated transceiver residing within the housing configured to relay signals from node-to-node up the wellbore, with each signal representing a packet of information that comprises an acoustic waveform representing fluid flow data; and

an independent power source also residing within the housing for providing power to the transceiver.

23. The method of claim 22, further comprising:

sending signals from the one or more sensors to the associated sensor communications nodes, the signals being indicative of one or more fluid flow parameters; and

sending acoustic signals from the sensor communications nodes to a receiver at a surface via the series of intermediate communications nodes and the topside communications node, node-to-node.

24. The method of claim 23, wherein the surface is an earth surface or production platform offshore.

25. The method of claim 23, wherein the one or more sensors for measuring fluid flow parameters are any of:

(i) fluid velocity measurement devices residing inside of the production tubing;

(ii) temperature sensors that measure temperature of fluids flowing inside of the production tubing;

(iii) pressure sensors that measure pressure inside of the production tubing, or pressure drop across a gas lift valve;

(iv) fluid density sensors that measure the density of fluids inside of the production tubing;

(v) microphones that provide passive acoustic monitoring to listen for the sound of gas entry into the production tubing or the opening and closing of the gas lift valve;

(vi) ultrasound sensors that correlate changes in gas transmission with gas flows, bubbles, solids and other properties of flow along gas inlets;

(vii) Doppler shift sensors;

(viii) chemical sensors;

(ix) an imaging device; and

(x) combinations thereof; and

each of the one or more sensor communications nodes is configured to receive signals from the associated sensor, and relay acoustic signals indicative of readings taken by the sensors.

26. The method of claim 25, wherein:

the one or more gas lift valves comprises at least two gas lift valves; and

the packet of information in each signal relayed by the transceivers further comprises an identifier for the sensor communications node that originally transmitted the signal.

27. The method of claim 26, wherein:

the wellbore comprises a production packer sealing an annulus between the production tubing and a surrounding string of casing;

each of the at least two gas lift valves resides above the production packer.

28. The method of claim 26, wherein the intermediate communications nodes are spaced apart such that each intermediate communications node resides on its own joint of production tubing.

29. The method of claim 26, wherein:

the intermediate communications nodes are spaced at about 10 to 100 foot (3.0 to 30.5 meter) intervals; and

the transceivers transmit data in acoustic form at a rate exceeding about 50 bps.

30. The method of claim 28, wherein the intermediate communications nodes transmit data representing the waveforms at a rate exceeding about 50 bps.

31. The method of claim 28, wherein a frequency band for the acoustic wave transmission by the transceivers is about 25 KHz wide.

32. The method of claim 28, wherein a frequency band for the acoustic wave transmission by the transceivers operates from about 75 kHz to 250 kHz.

33. The method of claim 28, wherein the acoustic waves provide data that is modulated by (i) a multiple frequency shift keying method, (ii) a frequency shift keying method, (iii) a multi-frequency signaling method, (iv) a phase shift keying method, (v) a pulse position modulation method, or (vi) an on-off keying method.

34. The method of claim 28, wherein:

each of the one or more sensors resides within the housing of its associated sensor communications node; and

an electro-acoustic transducer within the associated sensor communications node converts signals from the sensors into acoustic signals.

35. The method of claim 28, wherein:

a well head is placed above the wellbore; and

the topside communications node is placed (i) on an outer surface of the well head, or (ii) on an outer surface of an uppermost joint of the pipe string.

36. The method of claim 28, wherein each of the intermediate communications nodes is attached to an outer wall of a joint of pipe by (i) an adhesive material, (ii) welding, or (iii) one or more mechanical fasteners.

37. The method of claim 28, wherein each of the sensor communications nodes also comprises an electro-acoustic transducer and associated transceiver residing within a housing, with the transceiver being designed to relay signals from node-to-node up the wellbore representing the fluid flow data.

38. The method of claim 37, wherein at least one intermediate communications node resides between adjacent sensor communications nodes.

39. The method of claim 37, wherein each of the at least two gas lift valves resides in a side pocket mandrel.

40. The method of claim 37, wherein the transceiver in each sensor communications node is configured to send its acoustic signals indicative of fluid flow data (i) according to a pre-programmed schedule, (ii) in the event that a condition of gas lift valve failure is identified, or (iii) only when interrogated by a user at the surface.

41. The method of claim 37, wherein:

each of the one or more sensors resides adjacent to the housing of its associated sensor communications node;

each of the one or more sensors is in electrical communication with its corresponding sensor communications node; and

the electro-acoustic transducer within the associated sensor communications node converts signals from the sensors into acoustic signals for the associated transceivers.

42. The method of claim 28, wherein:

each of the sensor communications nodes is attached to the pipe string by one or more clamps; and

the step of attaching the sensor communications nodes to the pipe string comprises clamping the communications nodes to an outer surface of the production tubing or a gas lift valve.

43. The method of claim 28, wherein the one or more sensors communicates electrically with the transducer of the associated sensor communications node wirelessly.

44. The method of claim 43, further comprising:

running each of the sensors into the wellbore on a working string after production from the wellbore has commenced; and

affixing each of the sensors to an inner diameter of the production tubing adjacent a side pocket mandrel or to an inside of a side pocket mandrel.

45. The method of claim 43, further comprising:

affixing each of the sensors to a gas lift valve before or after production from the wellbore has commenced;

running the gas lift valves sequentially into the wellbore at the end of a working string; and

inserting each gas lift valve into an associated side pocket mandrel along the production tubing.

46. The method of claim 45, further comprising:

analyzing the signals to evaluate operation of the at least two gas lift valves.