Piping assembly with probes utilizing addressed datagrams

• US 9,759,061 B2
• Filed: 06/16/2015
• Issued: 09/12/2017
• Est. Priority Date: 06/25/2014
• Status: Active Grant

• Current Assignee: Advanced Oilfield Innovations Incorporated
• Original Assignee: Advanced Oilfield Innovations Incorporated
• Inventors: Lerner, Daniel Maurice, Orban, Andre
• Primary Examiner(s): Kim, Kevin
• Application Number:
  US14/741,078
• Publication Number:
  US 20150377013A1
• Time in Patent Office: 819 Days
• Field of Search: 3408554, 3408555
• CPC Class Codes: E21B 34/06 in wells
• CPC Class Codes: E21B 34/16 Control means therefor being outside the borehole control systems for submerged well heads E21B33/0355
• CPC Class Codes: E21B 47/12 Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
• CPC Class Codes: G05B 15/02 electric
• CPC Class Codes: G05B 19/042 using digital processors G05B19/05 takes precedence
• CPC Class Codes: G05D 7/0629 characterised by the type of regulator means
• CPC Class Codes: G05D 7/0635 by action on throttling means G05D7/0688, G05D7/0694 take precedence
• CPC Class Codes: H04B 1/38 Transceivers, i.e. devices in which transmitter and receiver form a structural unit and in which at least one part is used for functions of transmitting and receiving
• CPC Class Codes: Y02P 90/02 Total factory control, e.g. smart factories, flexible manufacturing systems [FMS] or integrated manufacturing systems [IMS]

Abstract

A control system with probes for generating and utilizing at least one or more addressed datagrams that communicate information to and from devices along piping assemblies comprising; one or more transmitters, one or more receivers, and one or more controllers, wherein the transmitters transmit information via one or more addressed datagrams encoded within a working medium to one or more receivers among the piping assemblies, is described. Transmitters convert datagrams into signals that are transmitted within the working medium and the receivers receive signals from the transmitters and also convert signals from the working medium which is converted back into datagrams. The controllers receive and decode the datagrams so that the controllers selectively communicate and perform logical operations on piping assembly devices according to directions received from the addressed datagrams. The entire control system can function as a network of controllers, receivers, transmitters, and/or transponders as required by one or more users.

Claims

1. One or more probes located in piping assemblies that generate and/or utilize at least one or more addressed datagrams allowing communication from information contained within said datagrams, said probes comprising;

one or more addressable transponders having one or more controllers, wherein said transponders transmit and receive information via said one or more addressed datagrams encoded within said probes or within said piping assemblies wherein said probes are used for installing, inventorying, accessing, actuating, and/or controlling one or more down-hole device(s) in a wellbore assembly comprising marked sections along a length of an assembly, wherein components and/or portions of an original section of said assembly together function as unique readable active or passive markers, wherein said probes further comprising;

(i) a first ability to read said markers,

(ii) a second ability to act upon reading said markers using at least one reader by locating specific addresses within said wellbore assembly corresponding with commands having at least one signature obtained from energy sources that transmit data which is compiled into a datagram, wherein said energy sources are initiated either at the surface, bottom, or along the length of said wellbore assembly.

2. The probes of claim 1, wherein said transponders convert said datagrams into signals that are transmitted from said probe to said piping assemblies or from said piping assemblies to said probe and wherein said transponders receive and convert signals back into datagrams.

3. The probes of claim 1, wherein said one or more probes receive and decode one or more datagrams so that said transponders within said probe or within said piping assemblies selectively communicate and perform logical operations causing action on one or more controllable devices.

4. The probes of claim 1, wherein said probes transmit and receive information within a medium.

5. The probes of claim 1, wherein said medium is a mechanical, hydraulic, electrical, electromagnetic, optical, radioactive, and/or a chemical medium.

6. The probes of claim 1, wherein said transponders can be replaced with receivers and/or transmitters.

7. The probes of claim 3, wherein said actions are measurements and/or movements.

8. The probes of claim 1, wherein said datagrams send instructions requesting transmission of measurements.

9. The probes of claim 1, wherein said datagrams create and transmit new or existing datagrams.

10. The probes of claim 1, wherein said datagrams are existing and being utilized within a network.

11. The probes of claim 3, wherein said energy sources can be located either uphole or downhole using wellbore fluids within said wellbore assembly providing the ability for causing movement and/or measurement of said controllable devices.

12. A method for using the probes of claim 1, wherein inserting said markers in strategically placed locations along an axial and/or radial portion of said piping assemblies is creating one or more patterns or sequence of patterns and wherein said markers are comprised of components each possessing, identical or different selected material compositions with cross sectional areas corresponding to each of said components.

13. The method of claim 12, wherein at least two or more of said components are rings made from different materials with distinct measurable property differences along said length of said piping assemblies, wherein said rings collectively function by providing a readable identification (ID) code producing coded piping assemblies created when said one or more patterns or sequence of patterns are read.

14. The method of claim 12, wherein said components are materials with properties selected from one or more, in any combination, from a group consisting of electrically conductive, electrically resistive, electrically insulative, electrically capacitive, electrically inductive, magnetically permeable, magnetically non-permeable, magnetically polarized, sonically transmissive, sonically absorptive, optically reflective, optically absorptive, radiation absorptive, radiation emissive that exhibit one or more features of said materials and wherein said components can be rings comprising said materials.

15. The method of claim 12, wherein said readable ID code is read in precise locations along a length of said piping assembly.

16. The method of claim 15, wherein said locations are a specific address corresponding to a feature either at the surface of, or embedded in, said piping assemblies.

17. The method of claim 12, wherein said markers appear as multiple readable bars to a reader that is reading said permanent components of said piping assemblies.

18. The method of claim 17, wherein said multiple readable bars comprise a spatial, binary, and/or bar code.

19. The method of claim 18, wherein reading by scanning said code with a reader provides an ability for finding a specific address along said piping assembly and allows for carrying out an action at said address.

20. The method of claim 12, wherein said piping assemblies are a casing which can also function as a production collar within a borehole.

21. The method of claim 12, wherein said at least one reader is at least one probe and wherein said probe is an autonomous tool.

22. The method of claim 21, wherein said reader is one or more tethered probes.

23. The method of claim 12, wherein said probes function alone or in any combination as a plug, sensor, computer, recorder, detector, scanner, and/or barcode scanner.

24. The method of claim 20, wherein said probes detect material property differences within said permanent components within said sections along said length of said casing.

25. The method of claim 12, wherein said probes direct magnetic fields in a radial direction thereby measuring eddy currents and/or changes in eddy current intensity, and wherein said probes are shielded.

26. The method of claim 25, wherein said probes are unshielded.

27. The method of claim 25, wherein said probes are singularly, collectively, or in any combination, reading, transmitting, computing, recording, receiving, distinguishing, networking, and/or measuring, at least a portion of one or more datagrams from signals generated, emitted, and/or transmitted from said probes.

28. The method of claim 27, wherein said signals are being actively generated, emitted, and/or transmitted from said piping assemblies and can be converted into datagrams.

29. The method of claim 28, wherein said signals are passively generated, emitted, and/or transmitted from said piping assemblies.

30. The method of claim 12, wherein utilizing said probes and coded piping assemblies results in uninterrupted, unimpaired, detected material property changes in said markers by using detectable changes in eddy current values received from said coded piping assemblies.

31. The method of claim 30, wherein said probes are moving or stationary and wherein said signals are read while said probes are moving or stationary.

32. The method of claim 20, wherein said collar is moving or stationary.

33. The method of claim 12, wherein said one or more probes function as sensors that they sense changes in permanent components of selected material compositions along said length of said piping assemblies.

34. The method of claim 12, wherein said permanent components are placed as radial sections in and along said length of said piping assemblies.

35. The method of claim 12, wherein marking said markers is accomplished while said piping assemblies are one or more production collars being installed in one or more wellbores.

36. The method of claim 12, wherein providing said readable ID code to a reader assists in identifying specific borehole features.

37. The method of claim 36, wherein providing said readable ID code to a reader assists in identifying specific features within a wellbore casing.

38. The method of claim 36, wherein providing said readable ID code assists in identifying branching of a borehole casing.

39. The method of claim 36, wherein said readable ID code is being read by said reader when said reader is moving in either a forward or backward direction.

40. The method of claim 36, wherein said readable ID code is read by a reader on a wireline so that said code is translated into data, wherein said data is sent to an uphole surface of a wellbore.

41. The method of claim 36, wherein said readable ID code is read by a reader on a wireline which is conveyed by jointed piping, or continuous tubing, to said uphole surface.

42. The method of claim 36, wherein said readable ID code is read by a reader on a wireline which is conveyed by a tractor or pipe crawler.

43. The method of claim 36, wherein said readable ID code is read by a reader connected to equipment not limited to measuring, computing, recording, and/or actuating.

44. The method of claim 36, wherein said readable ID code is read by a reader moved by fluids in said wellbore and not limited to pumping and production of said fluids.

45. The method of claim 36, wherein said readable ID code is read by a reader moved by gravity.

46. The method of claim 36, wherein said readable ID code is read by a reader moved by buoyancy in said fluid.

47. The method of claim 36, wherein said readable ID code is read by a reader moved by self-propulsion.

48. The method of claim 36, wherein said reader takes action upon reading said readable ID code.

49. The method of claim 48, wherein said action releases mechanical keys.

50. The method of claim 48, wherein said action upon reading said readable ID code is actuating a mechanical, electrical, electromagnetic, magnetic, pneumatic, hydraulic, radioactive, or fiber optic circuit.

51. The method of claim 48, wherein said action upon reading readable ID code initiates measurements.

52. The method of claim 48, wherein said action upon reading readable ID code is communicating with a unique identifier to specifically identified equipment along a length of and including an uphole surface of said borehole.

53. The method of claim 52, wherein actuating communications is accomplished directly or remotely using wired or wireless communication signals.