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Publication numberUS20060102347 A1
Publication typeApplication
Application numberUS 10/525,550
Publication dateMay 18, 2006
Filing dateAug 29, 2003
Priority dateAug 30, 2002
Also published asWO2004020790A2, WO2004020790A3
Publication number10525550, 525550, US 2006/0102347 A1, US 2006/102347 A1, US 20060102347 A1, US 20060102347A1, US 2006102347 A1, US 2006102347A1, US-A1-20060102347, US-A1-2006102347, US2006/0102347A1, US2006/102347A1, US20060102347 A1, US20060102347A1, US2006102347 A1, US2006102347A1
InventorsDavid Smith
Original AssigneeSmith David R
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Method and apparatus for logging a well using fiber optics
US 20060102347 A1
Abstract
The invention is a system and method to log a wellbore, comprising a logging tool including a downhole power source to power the data transmission and logging tool, the logging tool adapted to be deployed in a wellbore environment, the logging tool taking at least one measurement of the wellbore environment, a fiber optic line in optical communication with the logging tool, and the logging tool transmitting the measurements on a real time basis through the fiber optic line to surface and converting the data at surface back into electrical data and processing the data at surface into a real time display of the data. In one embodiment, a continuous tube with one end at the earth's surface and the other end in the wellbore is attached to the logging tool and includes the fiber optic line disposed therein.
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Claims(86)
1. A system to log a wellbore, comprising:
a logging tool including at least one down hole power supply to power the logging tool and adapted to be deployed in a wellbore;
the logging tool adapted to send data from the wellbore;
a fiber optic line in optical communication with the logging tool; and
the logging tool transmitting the data on a real time basis through the fiber optic line.
2. The system of claim 1, wherein the data comprises at least one measurement of the wellbore environment.
3. The system of claim 1, wherein the data comprises status data from the logging tool.
4. The system of claim 1, wherein the fiber optic line is deployed within a conduit.
5. The system of claim 4, wherein the conduit is a tube.
6. The system of claim 4, wherein the logging tool is attached to the conduit.
7. The system of claim 4, wherein the conduit is deployed through a stuffing box installed on a wellhead.
8. The system of claim 7, wherein the stuffing box forms a seal with the outside wall of the conduit.
9. The system of claim 8, wherein the outside wall of the conduit is slidingly sealingly engaged with at least one additional seal located below the stuffing box.
10. The system of claim 4, wherein an outside wall of the conduit is slidingly sealingly engaged with at least one seal located in a wellhead.
11. The system of claim 4, wherein the conduit is deployed from a reel located at a surface of the wellbore.
12. The system of claim 11, wherein the reel is located on a vehicle.
13. The system of claim 1, wherein the logging tool is deployed and retrieved multiple times in the same wellbore.
14. The system of claim 12, wherein the logging tool is deployed and retrieved from multiple wellbores.
15. The system of claim 11, further comprising:
an optical slip ring functionally associated with the reel and the fiber optic line;
a receiver attached to the fiber optic line at the surface;
the optical slip ring adapted to allow the transmission of optic data to the static receiver while the conduit and fiber optic line therein move on the reel in and out of the wellbore,
16. The system of claim 1, wherein the fiber optic line is optically connected to a receiver adapted to receive the data.
17. The system of claim 16, wherein the receiver processes the data to be made available to an operator.
18. The system of claim 1, wherein a converter converts the data into optical signals to be transmitted through the fiber optic line.
19. The system of claim 18, wherein the converter is located downhole.
20. The system of claim 18, wherein a transmitter is located downhole and transmits the optical signals through the fiber optic line.
21. The system of claim 18, wherein:
a transmitter is located at a surface of the wellbore;
a modulator is located downhole;
the transmitter transmits an optical signal to the modulator; and
the modulator modulates the optical signal so that the return optical signal is etched with the data.
22. The system of claim 1, wherein:
a transmitter is located at a surface of the wellbore;
a modulator is located downhole;
the transmitter transmits an optical signal to the modulator; and
the modulator modulates the optical signal so that the return optical signal is etched with the data.
23. The system of claim 1, wherein the fiber optic line is installed into the conduit by way of fluid drag once the conduit is deployed in the wellbore.
24. The system of claim 1, wherein the fiber optic line acts as a distributed temperature sensor.
25. The system of claim 4, wherein a signal can be sent through the conduit to actuate a first downhole tool.
26. The system of claim 25, wherein the signal is applied pressure.
27. The system of claim 25, wherein the signal is a pressure pulse.
28. The system of claim 25, wherein the downhole tool is a packer.
29. The system of claim 25, wherein the downhole tool is a perforating gun.
30. The system of claim 25, wherein data is simultaneously sent through the fiber optic line.
31. The system of claim 25, wherein an optical signal can be sent through the fiber optic line to actuate a second downhole tool.
32. The system of claim 31, wherein the optical signal and the signal through the conduit occur simultaneously.
33. The system of claim 1, wherein a plurality of fiber optic lines are in optical communication with the logging tool.
34. A method of logging a wellbore, comprising:
deploying a logging tool in a wellbore;
powering the logging tool with a downhole power source sending data from the logging tool; and
transmitting the data to a surface of the wellbore on a real time basis through a fiber optic line that is in optical communication with the logging tool.
35. The method of claim 34, wherein the data comprises at least one measurement of the wellbore environment.
36. The method of claim 34, wherein the data comprises status of the logging tool.
37. The method of claim 34, further comprising deploying the fiber optic line within a conduit.
38. The method of claim 37, wherein the conduit is a tube.
39. The method of claim 37, further comprising attaching the logging tool to the conduit.
40. The method of claim 37, further comprising deploying the conduit through a stuffing box installed on a wellhead.
41. The method of claim 40, further comprising forming a seal between the stuffing box and the outside wall of the conduit.
42. The method of claim 37, further comprising deploying the conduit from a reel located at a surface of the wellbore.
43. The method of claim 42, further comprising positioning the reel on a vehicle.
44. The method of claim 42, further comprising deploying and retrieving the logging tool multiple times in the same wellbore.
45. The method of claim 43, further comprising deploying and retrieving the logging tool in multiple wellbores.
46. The method of claim 34, further comprising receiving the data in a receiver that is optically connected to the fiber optic line.
47. The method of claim 46, further comprising processing the data to be shown to an operator.
48. The method of claim 34, further comprising converting the data into optical signals to be transmitted through the fiber optic line.
49. The method of claim 48, further comprising locating the converter downhole.
50. The method of claim 48, further comprising locating a transmitter downhole that transmits the optical signals through the fiber optic line.
51. The method of claim 48, further comprising:
transmitting an optical signal from a transmitter located at a surface of the wellbore to a modulator located downhole; and
modulating the optical signal so that the return optical signal is etched with the data.
52. The method of claim 34, further comprising installing the fiber optic line into the conduit by way of fluid drag once the conduit is deployed in the wellbore.
53. The method of claim 34, further comprising taking a distributed temperature measurements by use of the fiber optic line.
54. The method of claim 37, further comprising sensing a signal through the conduit to actuate a downhole tool.
55. The method of claim 54, wherein the signal is applied pressure.
56. The method of claim 54, wherein the signal is a pressure pulse.
57. The method of claim 54, wherein the downhole tool is a packer.
58. The method of claim 54, wherein the downhole tool is a perforating gun.
59. The method of claim 34, wherein a plurality of fiber optic lines are in optical communication with the logging tool.
60. A system to be deployed in a wellbore, comprising:
a continuous conduit extending within the wellbore;
a fiber optic line disposed within the conduit and adapted to transmit optical signals therethrough;
wherein a signal is traveling through the conduit simultaneously with an optical signal traveling through the fiber optic line.
61. The system of claim 60, wherein the signal traveling through the conduit is a pressure signal.
62. The system of claim 61, wherein the pressure signal is applied pressure.
63. The system of claim 61, wherein the pressure signal is a pressure pulse.
64. The system of claim 60, wherein the optical signal represents data.
65. The system of claim 60, wherein the optical signal is a signal to actuate a first downhole tool.
66. The system of claim 65, wherein the signal through the conduit is a signal to actuate a second downhole tool.
67. The system of claim 60, wherein the signal through the conduit is a signal to actuate a downhole tool.
68. A method for transmitting signals in a wellbore, comprising:
deploying a continuous conduit within the wellbore;
disposing a fiber optic line within the conduit, the fiber optic line adapted to transit optical signals therethrough; and
transmitting a signal through the conduit at the same time an optical signal is transmitted through the fiber optic line.
69. The method of claim 68, wherein the transmitting step comprises transmitting a pressure signal through the conduit.
70. The method of claim 69, wherein the pressure signal is applied pressure.
71. The method of claim 69, wherein the pressure signal is a pressure pulse.
72. The method of claim 68, wherein the optical signal represents data.
73. The method of claim 68, further comprising triggering the actuation of a first downhole tool with the optical signal.
74. The system of claim 73, further comprising triggering the actuation of a second downhole tool with the signal.
75. The system of claim 68, further comprising triggering the actuation of a second downhole tool with the signal.
76. A method of transmitting optical signals through a fiber optic line, comprising:
deploying the fiber optic line in a subterranean wellbore;
transmitting an optical signal representing data through the fiber optic line; and
simultaneously transmitting another optical signal through the fiber optic line for activating a downhole tool.
77. A system to be deployed in a wellbore, comprising:
a continuous conduit extending within the wellbore;
the continuous conduit being deployed from a reel;
a fiber optic line disposed with the conduit and adapted to sense a physical parameter,
wherein the conduit is adapted to be deployed and retrieved from a plurality of wellbores by spooling and unspooling the reel.
78. The system of claim 77, wherein the physical parameter is temperature or strain.
79. The system of claim 78, wherein the physical parameter is measured along the length of the fiber optic line.
80. The system of claim 77, wherein a battery powered memory tool is attached to the conduit to measure another physical parameter.
81. The system of claim 80, wherein the another physical parameter is pressure.
82. A method for use in a wellbore, comprising:
unspooling a conduit from a reel so as to deploy the conduit within a wellbore;
housing an optical fiber in the conduit;
sensing a physical parameter by use of the optical fiber;
spooling the conduit onto the reel so as to retrieve the conduit from the wellbore so that the conduit may be deployed and retrieved from a plurality of wellbores.
83. The method of claim 82, wherein the physical parameter is temperature or strain.
84. The method of claim 83, wherein the physical parameter is measured along the length of the fiber optic line.
85. The method of claim 82, further comprising measuring a physical parameter with a battery powered memory tool attached to the conduit.
86. The method of claim 85, wherein the another physical parameter is pressure.
Description
BACKGROUND

This invention generally relates to the logging and perforating of subterranean wells. More particularly, the invention relates to the logging of such wells using a fiber optic line.

Prior art logging systems have been deployed via electric wireline, known to those familiar with the art as braided cable, and via slickline. Wireline deployed logging systems are able to transmit the data collected by the logging tool real time through the electrically conductive copper wire, which is braided in with the braided steel wire. Although wireline deployed logging systems are able to transmit data real time via the electrical wires, such systems require a grease injector in order to ensure that pressure from the wellbore does not escape around the wireline as it is inserted into a pressurized well during deployment and use. Grease injectors, however, are problematic instruments to use, since they have a great tendency to leak under pressure and continual wear, and they present an environmental hazzard when such leaks occur.

On the other hand, current slickline deployed lines are manufactured from solid wire and are not able to transmit the logging tool data real time to surface. Instead, slickline deployed logging systems use memory tools connected to the lower end of the line. In slickline memory logging, the slickline and memory tool are lowered downhole on the end of the slickline and the memory tool is used to record the downhole logging tool data for subsequent download and collection at the surface once the tools are retrieved from the well. The advantages of slickline deployed systems are that they are much less costly and easier to deploy than wireline deployed systems, they can be run in the hole and out of the hole faster than braided wire, and they are easier to seal against well pressures at the well head.

Thus, there exists a continuing need for an arrangement and/or technique that addresses one or more of the problems that are stated above. In particular, the prior art would benefit from a logging system that has the capability of transmitting the logging tool data real time to surface and that is as economical and as easy to deploy as slickline deployed systems.

SUMMARY

The invention is a system and method to log a wellbore, comprising a logging tool including a downhole power source to power the data transmission and logging tool, the logging tool adapted to be deployed in a wellbore environment, the logging tool taking at least one measurement of the wellbore environment, a fiber optic line in optical communication with the logging tool, and the logging tool transmitting the measurements on a real time basis through the fiber optic line to surface and converting the data at surface back into electrical data and processing the data at surface into a real time display of the data. In one embodiment, a continuous tube with one end at the earth's surface and the other end in the wellbore is attached to the logging tool and includes the fiber optic line disposed therein.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 is a schematic of one embodiment of the logging system of this invention

FIG. 2 is a schematic of another embodiment of the logging system of this invention.

DETAILED DESCRIPTION

FIG. 1 shows the logging system 10 of the present invention disposed in a wellbore 5. Wellbore 5 may be cased. The logging system 10 includes at least one logging tool 12 and at least one fiber optic line 14. The logging system 10 includes at least one downhole power source 16, which can be a chemical battery, an optical to electrical power convertor, or a hydraulic turbine to electrical power convertor, to provide power to the different subcomponents 17 of the logging tool 12 including down hole data transmitters and receivers. A converter 18 is functionally attached to the logging tool 12 and the fiber optic line 14 and is located downhole in one environment. The converter 18 converts the electrical signals produced by the logging tool subcomponents 17 into optical signals that are then transmitted by an optical transmitter 20 through the fiber optic line 14 to the surface. Data collected by the logging tool subcomponents 17 is thus converted into electrical signals which are then converted into optical signals by the converter 18 and transmitted real time to the surface by the optical transmitter 20. Other data, such as tool status reports (i.e., active/not active, battery power, malfunctioning), may also be sent from the logging tool 12 through the fiber optic line 14 to the surface on a real time basis.

Logging tool subcomponents 17 may include but are not necessarily limited to a pressure sensor 22, a flow sensor 24 such as spinner 26, a gamma ray tool 28, a casing collar locator 30, an acoustical cement bond quality monitor, etc. Each subcomponent 17 collects its data and generates electrical signals indicative of such data. The electrical signals are then converted to optical signals as previously described. Other data gathering tools or subcomponents may include electrical or optical fluid analyzers, temperature sensors, chemical property sensors, and temperature sensors. In this application, the term “logging tool” is thus a tool that measures at least one parameter of the wellbore, wellbore environment, wellbore fluids, or formation (collectively referred to as “wellbore environment”). Likewise, the term “logging” is the taking of measurements of at least one parameter of the wellbore, wellbore environment, wellbore fluids, or formation (collectively referred to as “wellbore environment”). Logging can occur while the tools are held stationary at a given depth or while the tools are moved up and down in the well bore simultaneously gathering data and transmitting said data to the surface through at least one optic fibre. It is understood that the term “logging tool” may include a plurality of subcomponents, each of which may measure a different parameter. In addition, a plurality of logging tools 12, each with at least one or a plurality of subcomponents 17, may also be used with this invention.

In one embodiment, the fiber optic line 14 is disposed within a conduit 32, which protects the fiber optic line 14 from the harsh wellbore fluids and environment. Conduit 32 also protects fiber optic line 14 from strain that may otherwise be induced during the deployment, logging, and recovery operations of the tools and optic fibre tube. Logging tool 12, as well as spinner 26, converter 18, and optical transmitter 20, are attached to the conduit 32, therefore the fiber optic line 14 located within the conduit 32 does not feel the weight of the logging tool 12. Conduit 32 is preferably a small diameter tube, such as 3/16 inches, that has a wall thickness large enough to support the logging tool 12 in addition to the weight of the tube and optic fibres disposed therein In one embodiment, conduit 32 may be deployed on a reel such that the tube, fibres, and tools can be recovered a plurality of times from wells, the tools subsequently disconnected at surface and the reel with the tube and optic fibres can thus be transported to subsequent wells where tools will be reconnected to the tube and then redeployed in a different well. In one embodiment, Conduit 32 is a continuous tube that extends from the surface to the downhole logging tool(s) 12.

Wellhead 34 is located at the top of wellbore 5. Conduit 32 with fiber optic line 14 therein is passed through a stuffing box 36 or a packing assembly located on wellhead 34. Stuffing box 36 provides a seal against conduit 32 so as to safely allow the deployment of logging system 12 even if wellbore 5 is pressurized. In one embodiment, at least one additional seal 70, such as an elastomeric seal, can be located below the stuffing box 36 to provide an additional sealing engagement against the conduit 32 in order to prevent leaks from the pressurized wellbore escaping around the outer diameter of the conduit 32.

Conduit 32 may be deployed from a reel 38 that may be located on a vehicle 40. Several pulleys 42 may be used to guide the conduit 32 from the reel 38 into the wellbore 5 through the stuffing box 36 and wellhead 34. Based on the size of the conduit 32, deployment of the invention does not require a coiled tubing unit nor a large winch truck. Reel 38, in one embodiment, has a diameter of approximately 22 inches. Being able to use a smaller reel and vehicle than prior art coiled tubing logging with electrical and braided wire deployed logging systems dramatically reduces the cost of the operation.

Fiber optic line 14 is connected to a receiver 44 that may be located in the vehicle 40. Receiver 44 receives the optical signals sent from the logging tool 12 through the fiber optic line 14. Receiver 44, which would typically include a microprocessor and an optoelectronic unit, converts the optical signals back to electrical signals and then delivers the data (the electrical signals) to a processor, which processes the data and enables the presentation of the data to a user at surface. Delivery to the user can be in the form of graphical display on a computer screen or a print out or the raw data transmitted from the logging tool 12. In another embodiment, receiver 44 is a computer unit, such as lap top computer, that plugs into the fiber optic line 14. In another embodiment, the data is transmitted at surface to an internet and presented to users via a portal on the internet. In each embodiment, the surface receiver 44 processes the optical signals or data from the down hole logging tools and optic fibre to provide the chosen data output to the operator. The processing can include data filtering and analysis to facilitate viewing of the data.

An optical slip ring 39 is functionally attached to the reel 38 and enables the connection and dynamic optical communication between the fiber optic line 14 and the receiver 44 while the reel is turning running the tube into the well or pulling the tube out of the well. The optical slip ring 39 interfaces between the fiber optic line 14 that is turning with the reel and the stationary optic fibre at the surface. The slip ring 39 thus facilitates the transmission of the real time optical data between the dynamically moving optic fibre inside the moving reel 38 and the stationary receiver 44 at surface. In short, the slip ring 39 allows for the communication of optical data between a stationary optical fiber and a rotating optical fiber.

In one embodiment, a plurality of fiber optic lines 14 are disposed in conduit 32. The use of more than one fiber optic line 14 provides redundancy to the real time transmission of the data from the logging tool 12 to the surface as well as increased optical power transmission to down hole tools and other devices like power sources. The use of more than one fiber optic line 14 also allows for both single and multimode optical fiber to be run.

In one embodiment, conduit 32 is deployed with fiber optic line 14 already disposed therein. However, in another embodiment, conduit 32 is first deployed by itself, and fiber optic line 14 is thereafter installed in the conduit 32. In this technique, which is described in U.S. Reissue Pat. No. 37,283, fiber optic line 14 is pumped down conduit 32. Essentially, the fiber optic line 14 is dragged along the conduit 32 by the injection of a fluid at the surface, such as injection of fluid (gas or liquid) by pump 46. The fluid and induced injection pressure work to drag the fiber optic line 14 along the conduit 32. This installation technique can be specially useful when a fiber optic line 14 requires replacement during a logging operation.

In the embodiment shown in FIG. 1, optical transmitter 20 is located downhole with the logging tool 12. In another embodiment shown in FIG. 2, the optical transmitter 20 is located at the surface (in vehicle 40, for instance) and a modulator 48 is located downhole proximate the logging tool 12. In this embodiment, the modulator 48 modulates the optical signal sent from the surface optical transmitter 20 in a way that transmits the relevant data from the logging tool 12. The modulator 48 changes a property of the optical signal, such as intensity, frequency, polarization state, and phase. In other words, the modulated signal effected by the modulator 48 becomes the optical signal with the data. Receiver 44 receives the modulated signal and converts it back into the logging tool 12 data. Modulator 48 may be a reflector functionally connected to the converter 18. Converter 18 may activate the modulator 48 depending on the electrical signals it is converting. In one embodiment, the modulator 48 also acts as the converter 18.

In addition to enabling the real-time transmission of the logging tool 12 data, use of a fiber optic line 14 also allows a distributed temperature measurement to be taken along the length of the fiber optic line 14 or the plurality of optic fibre lines disposed inside the tube. In this embodiment, an optical transmitter, such as 20, should be located at the surface. Generally, pulses of light at a fixed wavelength are transmitted from the optical transmitter 20 through the fiber optic line 14. At every measurement point in the line 14, light is back-scattered and returns to the surface equipment 44. Knowing the speed of light and the moment of arrival of the return signal enables its point of origin along the fiber line 14 to be determined. Temperature stimulates the energy levels of the silica molecules in the fiber line 14. The back-scattered light contains upshifted and downshifted wavebands (such as the Stokes Raman and Anti-Stokes Raman portions of the back-scattered spectrum) which can be analyzed to determine the temperature at origin. In this way the temperature of each of the responding measurement points in the fiber line 14 can be calculated by the equipment 44, providing a complete temperature profile along the length of the fiber line 14. This general fiber optic distributed temperature system and technique is known in the prior art. If this technique is used, the fiber optic line 14 would be connected to a distributed temperature measurement system receiver, which can be a unit within the receiver 44 and which can be an optical time domain reflectrometry unit. The fiber optic line 14 can be used concurrently as a transmitter of data from the logging tool 12, a transmitter of downhole tool activation signals (as will be described), and as a sensor/transmitter of distributed temperature measurement. In another embodiment, fiber optic line 14 may be used to take a distributed strain measurement along the length of the fiber optic line(s) 14.

For the avoidance of doubt, in one embodiment the fiber optic line 14 may be completely housed in conduit 32 and used as a sensor/transmitter of at least one measurement without also being connected to a subcomponent 17. As discussed, the measurement may comprise distributed temperature or distributed strain, among others. In this case, a log (of the particular measurement) of many wells may be performed by successively deploying and retrieving the conduit 32 and optical fiber 14 from each well. In one embodiment, a battery powered memory tool, such as a gauge, may be attached to the conduit 32, such as at the bottom of the conduit 32, to measure and record a physical parameter, such as pressure. The measurements recorded by the tool are then downloaded and analyzed when the conduit 32 and tool are retrieved to the surface of the well.

In one embodiment, conduit 32, with fiber optic line 14 therein, may also be used to actuate downhole devices. Conduit 32 may be pressurized with a fluid, wherein the pressurized fluid actuates downhole tools such as a packer 50 or a perforating gun 52. The activation signal may be applied pressure above a certain threshold or pressure pulses with a specific signature. The downhole tool includes a signal receptor, such as a ratchet mechanism, shear pinned firing head, or a pressure transducer, which receives the activation signal and activates the downhole tool if the correct signal is received by the receptor. For instance, packer 50 may actuate to grip and seal against the wellbore walls, or thereafter, to ungrip and unseal from the wellbore walls. Also, perforating gun 52 may actuate to shoot the shaped charges 55 and create perforations 54 in the wellbore. Other downhole tools that may be activated include flow control valves, including sleeve valves and ball valves, samplers, sensors, or pumps.

In another embodiment, the same downhole tools described in the previous paragraph may be activated by optical signals sent through the fiber optic line 14 (instead of pressure signals sent through the conduit 32). In this embodiment, the downhole tool is functionally connected to the fiber optic line 14 so that a specific optical signal frequency, signal, wavelength or intensity activates the downhole tool. A photovoltaic converter can be used to facilitate the reception of the optical signal. In another related embodiment, the downhole tool is connected to a fiber optic line 14 that is not used for logging data transmission to the surface.

In another embodiment, pressure pulses through the conduit 32 and optical signals through a fiber optic line 14 can both be sent to activate the downhole tools. In one embodiment, pressure pulses through the conduit 32 and optical signals through a fiber optic line 14 can be sent simultaneously to activate different downhole tools. In another embodiment, data in the form of optical signals can be transmitted through the fiber optic line 14 at the same time pressure signals are transmitted through the conduit 32. In yet another embodiment, data in the form of optical signals and activation commands in the form of optical signals can be sent simultaneously through the fiber optic line 14.

FIGS. 1 and 2 show the use of logging system 10 is a land well. However, logging system 10 can also be used in off shore wells on platforms or located at subsea.

In operation, an operator first connects stuffing box 36 on top of wellhead 34 and begins to deploy conduit 32 from the reel 38 and into wellbore 5. As previously stated, the stuffing box 36 seals against the outside wall of the conduit 32 enabling the deployment of the logging system 10 in a wellbore 5 that is pressurized. In general, the logging tool 12 is lowered to the appropriate depth in the well and the subcomponents 17 take their relevant readings as the tools are moved in the well. In another embodiment the tools are held stationary and data is gathered whilst the tubing, tools, and optic fibre are stationary in the well. In the embodiment in which the fiber optic line 14 is deployed after the conduit 32 is in place, the pump 46 is activated and the pumped fluid acts to drag the fiber optic line 14 down the conduit 32.

The data measured by the subcomponents 17 is converted from electrical signals to optical signals by the converter 18. The optical signals are then transmitted through the fiber optic line 14 to the receiver 44 at the surface. In the embodiment in which the optical transmitter 20 is located downhole, the transmitter sends the relevant optical signals from the downhole location through the fiber optic line 14. In the embodiment in which the optical transmitter 20 is located at the surface, the transmitter 20 sends an unmodulated signal to the logging tool 12 and the modulator 48 modulates the signal so as to etch the data onto the signal that returns to the receiver 44. In all embodiments and through the use of the fiber optic line 14, the data measured by the logging tool 12 is sent to the receiver 44 real time.

For instance, logging tool 12 may be lowered so that spinner 26 and the other subcomponents 17 are adjacent perforations 54 and formation 57 so as to obtain accurate and real time data of the parameters adjacent such perforations 54 and formation 57. In the embodiment in which the fiber optic line 14 is also used as a distributed temperature measurement system, the distributed temperature measurements may be used to approximately determine flow along the length of the wellbore 5 (across different perforations), since flow acts to change the temperature along the fiber optic line 14. Furthermore, this inferred distributed flow profile along the well can subsequently be correlated with the spinner logging tool located on the lower end of the conduit 32. Using the distributed temperature measurement to approximately determine flow indicates to an operator which areas or perforations in the wellbore 5 should be correlated with the logging tool 12, such as by taking the real flow measurement using spinner 26.

The downhole tools, such as packer 50 and perforating gun 52, may be activated at any point by way of pressure signals or hydraulicly transmitted energy through the conduit 32 or optical signals through a fiber optic line 14. Having the ability to perforate a formation and then log the relevant formation in the same trip saves time and money.

Once the logging operation is completed, the logging tool 12 is raised by reversing reel 38. It is appreciated that reel 38 and the relative size of conduit 32 enables the repeated and simple deployment and retrieval of logging tool 12. Placing reel 38 on vehicle 40 or otherwise making the reel portable enables the logging system 10 to be used in multiple wellbores.

In the embodiment including only the optical fiber as a sensor of a particular measurement (such as distributed temperature or strain), the conduit 32 is deployed in the well, the measurement is taken, and the conduit 32 is then retrieved from the well. The system may then be taken to other wellsites. In the embodiment including a battery powered memory tool, such as a gauge, the measurements taken and recorded by the tool are downloaded from the tool once the conduit 32 and tool are retrieved to the surface.

While the invention has been disclosed with respect to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover all such modifications and variations as fall within the true spirit and scope of the invention.

Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US7859654Jul 17, 2008Dec 28, 2010Schlumberger Technology CorporationFrequency-scanned optical time domain reflectometry
US8522869Sep 29, 2009Sep 3, 2013Schlumberger Technology CorporationOptical coiled tubing log assembly
US20100309750 *Sep 8, 2009Dec 9, 2010Dominic BradySensor Assembly
WO2010009007A1 *Jul 10, 2009Jan 21, 2010Schlumberger Canada LimitedFrequency-scanned optical time domain reflectometry
Classifications
U.S. Classification166/254.2, 166/66
International ClassificationE21B23/00, G01K11/32, E21B47/12
Cooperative ClassificationG01K11/32, E21B23/00, E21B47/065, E21B47/123
European ClassificationE21B23/00, G01K11/32, E21B47/12M2, E21B47/06B
Legal Events
DateCodeEventDescription
Jan 4, 2006ASAssignment
Owner name: SCHLUMBERGER TECHNOLOGY CORPORATION, TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:SMITH, DAVID;REEL/FRAME:017415/0692
Effective date: 20051215