U.S. patent application number 10/525550 was filed with the patent office on 2006-05-18 for method and apparatus for logging a well using fiber optics.
Invention is credited to David R. Smith.
Application Number | 20060102347 10/525550 |
Document ID | / |
Family ID | 31981462 |
Filed Date | 2006-05-18 |
United States Patent
Application |
20060102347 |
Kind Code |
A1 |
Smith; David R. |
May 18, 2006 |
Method and apparatus for logging a well using fiber optics
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.
Inventors: |
Smith; David R.; (Kilgore,
TX) |
Correspondence
Address: |
SCHLUMBERGER OILFIELD SERVICES
200 GILLINGHAM LANE
MD 200-9
SUGAR LAND
TX
77478
US
|
Family ID: |
31981462 |
Appl. No.: |
10/525550 |
Filed: |
August 29, 2003 |
PCT Filed: |
August 29, 2003 |
PCT NO: |
PCT/GB03/03764 |
371 Date: |
January 3, 2006 |
Current U.S.
Class: |
166/254.2 ;
166/66 |
Current CPC
Class: |
E21B 23/00 20130101;
G01K 11/32 20130101; E21B 47/135 20200501; E21B 47/07 20200501 |
Class at
Publication: |
166/254.2 ;
166/066 |
International
Class: |
E21B 47/00 20060101
E21B047/00 |
Foreign Application Data
Date |
Code |
Application Number |
Aug 30, 2002 |
US |
60407074 |
Feb 24, 2003 |
US |
60449730 |
Claims
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
[0001] 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.
[0002] 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.
[0003] 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.
[0004] 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
[0005] 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
[0006] FIG. 1 is a schematic of one embodiment of the logging
system of this invention
[0007] FIG. 2 is a schematic of another embodiment of the logging
system of this invention.
DETAILED DESCRIPTION
[0008] 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.
[0009] 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.
[0010] 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.
[0011] 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.
[0012] 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.
[0013] 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.
[0014] 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.
[0015] 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.
[0016] 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.
[0017] 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.
[0018] 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.
[0019] 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.
[0020] 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.
[0021] 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.
[0022] 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.
[0023] 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.
[0024] 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.
[0025] 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.
[0026] 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.
[0027] 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.
[0028] 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.
[0029] 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.
[0030] 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.
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