U.S. patent application number 15/324402 was filed with the patent office on 2017-06-08 for depth positioning using gamma-ray correlation and downhole parameter differential.
This patent application is currently assigned to Schlumberger Technology Corporation. The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Carlos Merino, Fadhel Rezgui.
Application Number | 20170159423 15/324402 |
Document ID | / |
Family ID | 51260796 |
Filed Date | 2017-06-08 |
United States Patent
Application |
20170159423 |
Kind Code |
A1 |
Merino; Carlos ; et
al. |
June 8, 2017 |
DEPTH POSITIONING USING GAMMA-RAY CORRELATION AND DOWNHOLE
PARAMETER DIFFERENTIAL
Abstract
Methods, systems, and apparatuses for determining the location
or depth in a wellbore of a tubular string (15) or downhole
component is provided. One method may include placing a tubular
string (15) having a depth measurement module (102) into a
wellbore, the wellbore emanating radiation at at least one location
along the wellbore and determining the location of the depth
measurement module (102) in the wellbore based on a correlation
between a wellbore property that is a function of depth and a
radiation intensity at at least one location within the
wellbore.
Inventors: |
Merino; Carlos; (Clamart,
FR) ; Rezgui; Fadhel; (Clamart, FR) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Assignee: |
Schlumberger Technology
Corporation
Sugar Land
TX
|
Family ID: |
51260796 |
Appl. No.: |
15/324402 |
Filed: |
July 9, 2015 |
PCT Filed: |
July 9, 2015 |
PCT NO: |
PCT/EP2015/001409 |
371 Date: |
January 6, 2017 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62188457 |
Jul 2, 2015 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 47/12 20130101;
E21B 47/053 20200501; E21B 49/00 20130101; E21B 47/06 20130101;
E21B 47/07 20200501; E21B 47/09 20130101 |
International
Class: |
E21B 47/04 20060101
E21B047/04; E21B 49/00 20060101 E21B049/00; E21B 47/12 20060101
E21B047/12; E21B 47/09 20060101 E21B047/09 |
Foreign Application Data
Date |
Code |
Application Number |
Jul 10, 2014 |
EP |
14290206.3 |
Claims
1. A method, comprising: placing a tubular string having at least
one depth measurement module into a wellbore, the wellbore
emanating radiation at at least one location along the wellbore;
and determining the location of the depth measurement module in the
wellbore based on a correlation between a wellbore property that is
a function of depth and a radiation intensity at at least one
location within the wellbore.
2. The method of claim 1, further comprising: determining a length
change, L.sub..DELTA., of the tubular string in the wellbore
utilized in order to obtain the wellbore property that is a
function of depth and the radiation intensity at at least one
location within the wellbore; and wherein the correlation between
the wellbore property and the radiation intensity for determining
the location of the depth measurement module in the wellbore
further includes the length change L.sub..DELTA. of the tubular
string in the wellbore.
3. The method of claim 1, further comprising: repositioning the
depth measurement module to a desired wellbore location based on
the determined location.
4. The method of claim 1, further comprising: determining a
plurality of wellbore properties that are a function of depth and
plurality of radiation intensities at a plurality of locations
along the wellbore.
5. The method of claim 4, wherein the at least one location along
the wellbore emanating radiation is a known location in the
wellbore.
6. The method of claim 5, wherein the wellbore has a plurality of
known locations that emanate radiation and which form a known
pattern of radiation intensity, thereby providing a radiation
intensity signature along the wellbore.
7. The method of claim 4, wherein the plurality of locations
comprise: locations above a radioactive source along the wellbore,
at the radioactive source, and below the radioactive source.
8. The method of claim 1, wherein the radiation emanating from the
wellbore is caused by a radioactive source located along the
wellbore, the radioactive source comprising at least one of an
artificial radioactive source and a natural radioactive source.
9. The method of claim 8, wherein the artificial radioactive source
comprises a pip-tag and the natural radioactive source comprises a
natural background radiation emanating from a formation in which
the wellbore is formed.
10. The method of claim 9, further comprising: measuring the
wellbore property at a first location above the pip-tag,
DP.sub.start; measuring the wellbore property at a second location
when the depth measurement module is at the radioactive pip-tag,
DP.sub.pip; and measuring the wellbore property at a third location
in the wellbore below the pip-tag DP.sub.end.
11. The method of claim 10, further comprising: determining a
length change, L.sub..DELTA., of the tubular string in the wellbore
utilized in order to obtain a plurality of wellbore properties that
are a function of depth and a plurality of radiation intensities at
a plurality of locations along the wellbore, wherein determining
the length change L.sub..DELTA. of the tubular string in the
wellbore further comprises: measuring a first distance, h.sub.1,
from a rig floor to a top of the tubular string when the depth
measurement module is at the first location in the wellbore;
connecting one or more tubulars of known length L to the tubular
string; lowering the tubular string into the wellbore; and
measuring a second distance, h.sub.2, from the rig floor to the top
of the tubular string when the tubular string is at the third
location.
12. The method of claim 11, wherein determining the location of the
depth measurement module in the wellbore further comprises:
determining a distance travelled by the tubular string based on a
correlation of h.sub.1, h.sub.2, L, and the measured wellbore
properties at the first, second, and third locations, DP.sub.start,
DP.sub.pip, DP.sub.end.
13. The method of claim 1, further comprising: transmitting signals
representing at least one of a radiation intensity and the wellbore
property from the depth measurement module to a wellbore surface
system.
14. The method of claim 1, wherein the wellbore property comprises
at least one of temperature, pressure, density, gravity, and
acceleration.
15. The method of claim 1, wherein the tubular string includes two
or more depth measurement modules placed at a known distance apart
from each other along the tubular sting.
16. A method of determining the position of a downhole tubular
string in a wellbore, comprising: placing a tubular string having a
depth measurement module into a wellbore having a radioactive
pip-tag; measuring a first distance, h.sub.1, from a rig floor to a
top of the tubular string when the depth measurement module is at a
first location in the wellbore above the pip-tag; measuring a
wellbore property at the first location, DP.sub.start, using the
depth measurement module; connecting one or more tubulars of known
length L to the tubular string; lowering the tubular string into
the wellbore; measuring the wellbore property at a second location
when the depth measurement module is at the radioactive pip-tag,
DP.sub.pip; measuring the wellbore property at a third location in
the wellbore below the pip-tag, DP.sub.end; measuring a second
distance, h.sub.2, from the rig floor to the top of the tubular
string when the tubular string is at the third location; and
determining the location of the depth measurement module in the
wellbore based on a correlation of h.sub.1, h.sub.2, L, and the
measured wellbore properties at the first, second, and third
locations, DP.sub.start, DP.sub.pip, and DP.sub.end.
17. The method of claim 16, further comprising: measuring a
radiation intensity at the first, second, and third locations; and
repositioning the depth measurement module to a desired wellbore
location based on the determined location.
18. The method of claim 16, further comprising: transmitting
signals representing at least one of a radiation sensor and the
wellbore property from the depth measurement module to a wellbore
surface system.
19. An apparatus, comprising: a tubular string having a depth
measurement module, wherein the depth measurement module comprises:
a telemetry device; a wellbore property sensor, wherein the sensed
wellbore property is a function of depth; and a radiation
sensor.
20. A system for determining the position of a downhole tubular
string in a wellbore, comprising: a tubular, string having a depth
measurement module disposed in the wellbore, wherein the depth
measurement module comprises: a telemetry device; a wellbore
property sensor, wherein the sensed wellbore property is a function
of depth; and a radiation sensor; a radioactive source disposed at
a location along the wellbore; and a telemetry system for
communication between the depth measurement module and a wellbore
surface system.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to European Patent
Application No. 14290206.3 filed Jul. 10, 2014 and U.S. Provisional
Application Ser. No. 62/188,457 filed Jul. 2, 2015, which are
herein incorporated by reference.
BACKGROUND
[0002] This disclosure relates to placement of a tubular string,
such as a drill string or a tubing string, downhole in a wellbore,
and more particularly to methods and apparatuses for placing
downhole tools and tubular strings at a desired depth and location
in a wellbore.
DESCRIPTION OF THE RELATED ART
[0003] One of the more difficult problems associated with any
borehole system is to know the relative position and/or location of
a tubular string in relation to the formation or any other
reference point downhole. For example, in the oil and gas industry
it is sometimes desirable to place systems at a specific position
in a wellbore during various drilling and production operations
such as drilling, perforating, fracturing, drill stem or well
testing, reservoir evaluation testing, and pressure and temperature
monitoring.
[0004] Typically, in order to determine the depth or location of a
tool located on a tubular string in a wellbore, the number of
tubulars, such as pipe, tubing, collars, jars, etc., is counted as
the tubulars are lowered into the wellbore. The depth or location
of the drillstring or a downhole tool along the drillstring will
then be based on the number of components lowered into the wellbore
and the length of those components, such as the length of the
individual drill pipes, collars, jars, tool components, etc.
However, as a tubular string increases length as more components
are run in hole (RIH), e.g. at a string length of ca. 10,000 ft. or
longer, the tubular string often lacks stiffness and rigidity, and
may become somewhat elastic and flexible. Thus, when conveying the
tubular string into the wellbore, improper or inaccurate
measurements of the length, depth, and location of the tubular
string may take place due to inconsistent lengths of individual
components such as drill pipes, tubing, or other downhole
components, stretching of pipe and tubing components, wellbore
deviations, or other inaccuracies, resulting in improper placement
of the tubular string and associated downhole tools used for
various operations.
[0005] Therefore, there is a need to more accurately place and
determine the location of downhole tools and strings in a
wellbore.
SUMMARY
[0006] In some embodiments, methods, systems, and apparatuses for
determining the location or depth in a wellbore of a tubular string
or downhole component is provided. In some embodiments, a method
includes placing a tubular string having a depth measurement module
into a wellbore, the wellbore emanating radiation at at least one
location along the wellbore and determining the location of the
depth measurement module in the wellbore based on a correlation
between a wellbore property that is a function of depth and a
radiation intensity at at least one location within the
wellbore.
[0007] In some embodiments, a method includes placing a tubular
string having a depth measurement module into a wellbore having a
radioactive pip-tag. The method includes measuring a first
distance, h.sub.1, from a rig floor to a top of the tubular string
when the depth measurement module is at a first location in the
wellbore above the pip-tag and measuring a wellbore property at the
first location, DP.sub.start, using the depth measurement module.
The method also includes connecting at least one if not more
tubulars of known length L to the tubular string, lowering the
tubular string into the wellbore, and measuring the wellbore
property at a second location when the depth measurement module is
at the radioactive pip-tag, DP.sub.pip. The method also includes
measuring the wellbore property at a third location in the wellbore
below the pip-tag, DP.sub.end, and measuring a second distance,
h.sub.2, from the rig floor to the top of the tubular string when
the tubular string is at the third location. The method also
includes determining the location of the depth measurement module
in the wellbore based on a correlation of h.sub.1, h.sub.2, L, and
the measured wellbore properties at the first, second, and third
locations, DP.sub.start, DP.sub.pip, and DP.sub.end.
[0008] In some embodiments, an apparatus includes a tubular string
having a depth measurement module. The depth measurement module
includes a telemetry device, a wellbore property sensor and a
radiation sensor. The sensed wellbore property is a function of
depth.
[0009] In some embodiments, a system for determining the position
of a downhole tubular string in a wellbore includes a tubular
string disposed in the wellbore. The tubular string has a depth
measurement module. The depth measurement module includes a
telemetry device, a wellbore property sensor, and a radiation
sensor. The sensed wellbore property is a function of depth. The
system also includes a radioactive source disposed at a location
along the wellbore, and a telemetry system for communication
between the depth measurement module and a wellbore surface
system.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] So that the manner in which the above recited features can
be understood in detail, a more particular description may be had
by reference to embodiments, some of which are illustrated in the
appended drawings, wherein like reference numerals denote like
elements. It is to be noted, however, that the appended drawings
illustrate various embodiments and are therefore not to be
considered, limiting of its scope, and may admit to other equally
effective embodiments.
[0011] FIG. 1 shows a schematic view of a tubular string having an
acoustic telemetry system utilized in some embodiments described
herein.
[0012] FIG. 2 shows a schematic diagram of a depth measurement
module that is a part of the tubular string shown in FIG. 1.
[0013] FIG. 3 is a schematic view of a wellbore and a surface rig
above the wellbore.
[0014] FIG. 4A is a schematic view of a tubular string in a
wellbore according to some embodiments of the present
disclosure.
[0015] FIG. 4B is schematic view of a tubular string lowered in a
wellbore according to some embodiments of the present
disclosure.
[0016] FIG. 5 is a flow diagram illustrating a method of
determining the position of a downhole tubular string in a wellbore
according to some embodiments of the present disclosure.
[0017] FIG. 6 illustrates a graph showing one possible wellbore
property, pressure, and radiation intensity, a gamma-ray intensity,
vs. time according to some embodiments of the present
disclosure.
[0018] FIGS. 7A and 7B illustrate a wireline open-hole gamma-ray
log which may be used according to some embodiments of the present
disclosure
DETAILED DESCRIPTION
[0019] In the following description, numerous details are set forth
to provide an understanding of the present disclosure. It will be
understood by those skilled in the art, however, that the
embodiments of the present disclosure may be practiced without
these details and that numerous variations or modifications from
the described embodiments may be possible.
[0020] In the specification and appended claims: the terms
"connect", "connection", "connected", "in connection with", and
"connecting" are used to mean "in direct connection with" or "in
connection with via one or more elements"; and the term "set" is
used to mean "one element" or "more than one element". Further, the
terms "couple", "coupling", "coupled", "coupled together", and
"coupled with" are used to mean "directly coupled together" or
"coupled together via one or more elements". As used herein, the
terms "up" and "down", "upper" and "lower", "upwardly" and
downwardly", "upstream" and "downstream"; "above" and "below"; and
other like terms indicating relative positions above or below a
given point or element are used in this description to more clearly
describe some embodiments of the disclosure.
[0021] Embodiments generally described herein include systems,
devices, and methods of determining the location of a tubular
string in a wellbore, and positioning the tubular string at a
desired location within the wellbore. Some embodiments may include
a telemetry system for communicating information and transmitting
control signals between the surface and downhole components along
the tubular string. Some examples of telemetry systems that may be
used include, but are not limited to, electrical cable systems such
as wired drill pipe, fiber optic telemetry systems, and wireless
telemetry systems using acoustic and/or electromagnetic signals.
The telemetry systems may deliver status information and sensory
data to the surface, and control downhole tools directly from the
surface in real time or near real time conditions.
[0022] Although multiple types of telemetry systems may be used in
embodiments of the disclosure, to simplify the discussion of some
embodiments reference will be made to a wireless telemetry system,
such as the acoustic telemetry system shown in FIG. 1.
Additionally, it should be noted that multiple types of strings and
components used to make up tubular strings may be used in
embodiments of the disclosure. For example, drilling components may
be used to make up a drill string. Some drilling components may
include drill pipe, collars, jars, downhole tools, etc. Production
strings may generally include tubing and various tools for testing
or production such as valves, packers, and perforating guns, etc.
As used herein, the term tubular string includes any type of
tubular such as drilling or production pipes, tubing, components,
and tools used in a tubular string for downhole use, such as those
previously described. Thus, a tubular string includes, but is not
limited to, drill strings, tubing strings, production strings,
drill stem testing (DST) strings, and any other string in which
various types of tubing and/or tubing type tools are connected
together to form the tubular string.
[0023] Embodiments described herein may be used during any oil and
gas exploration, characterization, or production procedure in which
it is desirable to know and position the location of the tubular
string and/or a downhole component that is a part of the tubular
string within the wellbore. For example, embodiments disclosed
herein may be applicable to testing wellbores such as are used in
oil and gas wells or the like. FIG. 1 shows a schematic view of a
tubular string equipped for well testing and having an acoustic
telemetry system according to embodiments disclosed herein. Once a
wellbore 10 has been drilled through a formation, the tubing string
15 can be used to perform tests, and determine various properties
of the formation through which the wellbore has been drilled.
[0024] In the example of FIG. 1, the wellbore 10 has been lined
with a steel casing 12 (cased hole) in the conventional manner,
although similar systems can be used in unlined (open hole)
environments. In order to test the formations, it is desirable to
place a testing apparatus 13 in the well close to regions to be
tested, to be able to isolate sections or intervals of the well,
and to convey fluids from the regions of interest to the surface.
This is commonly done using tubular members 14, such as drill pipe,
production tubing, or the like (collectively, tubing 14), that,
when joined form a drill string or tubing string 15 which extends
from well-head equipment 16 at the surface (or sea bed in subsea
environments) down inside the wellbore 10 to a zone of interest
308. The well-head equipment 16 can include blow-out preventers and
connections for fluid, power and data communication.
[0025] A packer 18 is positioned on the tubing 14 and can be
actuated to seal the borehole around the tubing 14 at the zone of
interest 308. Various pieces of downhole equipment 20, are
connected to the tubing 14 above or below the packer 18. The
downhole equipment 20 may include, but is not limited to:
additional packers, tester valves, circulation valves, downhole
chokes, firing heads, TCP (tubing conveyed perforator), gun drop
subs, samplers, pressure gauges, downhole flow meters, downhole
fluid analyzers, and the like.
[0026] In the embodiment shown in FIG. 1, a tester valve 24 is
located above the packer 18, and the testing apparatus 13 is
located below the packer 18. The testing apparatus 13 could also be
placed above the packer 18 if desired. In order to support signal
transmission along the tubing 14 between the downhole location and
the surface, a series of wireless modems 25M.sub.i-2, 25M.sub.i-1,
25M, 25M.sub.i+1, etc. may be positioned along the tubular string
15 and mounted to the tubing 14 via any suitable technology, such
as gauge carriers 28a, 28b, 28c, 28d, etc. to form a telemetry
system 26. The tester valve 24 is connected to acoustic modem
25Mi+1. Gauge carrier 28a may also be placed adjacent to tester
valve 24, with a pressure gauge also being associated with each
wireless modem. As will be described in more detail below, the
tubular string 15 may also include a depth measurement module 102
for determining the location of the tubular string 15 within the
wellbore 10 and to position tools along the tubular string at
desired locations, such as a perforating gun 30 in a zone of
interest 308.
[0027] The wireless modems 25M.sub.i-2, 25M.sub.i-1, 25M,
25M.sub.i+1 can be of various types and communicate with each other
via at least one communication channel 29 using one or more various
protocols. For example, the wireless modems 25M.sub.i-2,
25M.sub.i-1, 25M, 25M.sub.i+1 can be acoustic modems, i.e.,
electro-mechanical devices adapted to convert one type of energy or
physical attribute to another, and may also transmit and receive,
thereby allowing electrical signals received from downhole
equipment 20 to be converted into acoustic signals for transmission
to the surface, or for transmission to other locations of the
tubular string 15. In this example, the communication channel 29 is
formed by the elastic media 17 such as the tubing 14 connected
together to form tubular string 15. It should be understood that
the communication channel 29 can take other forms. In addition, the
wireless modem 25M.sub.i+1 may operate to convert acoustic tool
control signals from the surface into electrical signals for
operating the downhole equipment 20. The term "data," as used
herein, is meant to encompass control signals, tool status signals,
sensory data signals, and any variation thereof whether transmitted
via digital or analog signals. Other appropriate tubular member(s)
(e.g., elastic media 17) may be used as the communication channel
29, such as production tubing, and/or casing to convey the acoustic
signals.
[0028] Wireless modems 25Mi+(2-10) and 25Mi+1 operate to allow
electrical signals from the tester valve 24, the gauge carrier 28a,
and the testing apparatus 13 to be converted into wireless signals,
such as acoustic signals, for transmission to the surface via the
tubing 14, and to convert wireless acoustic tool control signals
from the surface into electrical signals for operating the tester
valve 24 and the testing apparatus 13. The wireless modems can be
configured as repeaters of the wireless acoustic signals. The
modems can operate to transmit acoustic data signals from sensors
in the downhole equipment 20 along the tubing 14. In this case, the
electrical signals from the downhole equipment 20 are transmitted
to the acoustic modems which operate to generate an acoustic
signal. The modem 25Mi+2 can also operate to receive acoustic
control signals to be applied to the testing apparatus 13. In this
case, the acoustic signals are demodulated by the modem, which
operates to generate an electric control signal that can be applied
to the testing apparatus 13.
[0029] As shown in FIG. 1, in order to support acoustic signal
transmission along the tubing 14 between the downhole location and
the surface, a series of the acoustic modems 25Mi-1 and 25M, etc.
may be positioned along the tubing 14. The acoustic modem 25M, for
example, operates to receive an acoustic signal generated in the
tubing 14 by the modem 25Mi-1 and to amplify and retransmit the
signal for further propagation along the tubing 14. Thus an
acoustic signal can be passed between the surface and the downhole
location in a series of short and/or long hops.
[0030] The acoustic wireless signals, conveying commands or
messages, propagate in the transmission medium (the tubing 14) in
an omni-directional fashion, that is to say up and down the tubing
string 15. A wellbore surface system 58 is provided for
communicating between the surface and various tools downhole. The
wellbore surface system 58 may include a surface acoustic modem
25Mi-2 that is provided at the head equipment 16, which provides a
connection between the tubing string 15 and a data cable or
wireless connection 54 to a control system 56 that can receive data
from the downhole equipment 20 and provide control signals for its
operation.
[0031] FIG. 2 is a schematic diagram of a depth measurement module
102. In some embodiments, the depth measurement module 102 may be
configured to include a telemetry device 208 having a transmitter
and receiver for sending and/or receiving status requests and
sensory data, triggering commands, and synchronization data. The
depth measurement module 102 may also include one or more sensors
202 coupled to at least one processor 204. More than one processor
204 may also be used. The processor 204 may be coupled to the
telemetry device 208 and to a memory device 206 for storing sensor
data, parameters, and the like. The sensors 202 may include
radiation sensors and any type of downhole parameter or wellbore
property sensor, where the downhole parameter or wellbore property
is a function of depth. Examples of some sensors include, but are
not limited to, temperature based sensors, pressure based sensors,
gamma-ray sensors, gravity sensors, density sensors, and
accelerometers.
[0032] FIG. 3 shows a schematic view of another wellbore 310,
similar to the wellbore 10 shown in FIG. 1, and having casing 312.
A rig 300 having a rig floor 302 is positioned above the wellbore
310. A known zone of interest 308 is located at a certain depth
below the surface. The zone of interest 308 may include various
types of hydrocarbons, such, as oil and/or gas. The wellbore has a
total depth (TD) 304. A shooting depth (SD) 306 is located at the
beginning of the zone of interest 308. In some testing and/or
production operations, a perforating gun is positioned next to the
zone of interest 308 in order to fire the gun into the zone of
interest 308, and begin a well test or production, as previously
shown in FIG. 1. In some applications, the wellbore 310 may be a
non-vertical wellbore.
[0033] Ascertaining the position of the gun downhole may be
difficult, resulting in potential misfiring of the gun in a
sub-optimal location within the wellbore. It should be noted that
positioning a perforating gun at a desired location within a
wellbore is but one example of an operation where the location of
the tubular string or a downhole tool is desirable for performing
the operation. Other examples of well operations where accurate
placement of a tubing string and/or downhole tools within a
wellbore include but are not limited to well operations such as
placement of a packer assembly at a desired location along the
wellbore 310 and placement of pressure and temperature sensors in a
wellbore, such as may be done during well testing. As other types
of operations may involve knowing the location of the tubing string
or a downhole tool, FIGS. 4A and 4b simply shows a tubing string
315 having a depth measurement module 120 without any other
downhole tools that could also form a portion of the tubular string
315 such as was previously shown in FIG. 1.
[0034] FIGS. 4A and 4B show a schematic view of a tubular string
315 in a wellbore 310 emanating radiation at at least one location
along the wellbore 310. The radiation emanating from the wellbore
310 may be caused by a radioactive source 400 located along the
wellbore 310. The radioactive source may be an artificial source of
radiation, such as a radioactive pip-tag or a radiated activated
casing, or a natural radioactive source, such as the natural
background radiation emanating from the formation 311 in which the
wellbore 310 is formed. FIG. 5 shows a flow diagram illustrating a
method 500 of determining the position of a downhole tubular string
in a wellbore according to some embodiments of the present
disclosure. FIG. 6 illustrates a graph showing the tubular string
length and gamma-ray intensity vs. time according to some
embodiments of the present disclosure. FIGS. 7A and 7B illustrate a
wireline open-hole gamma-ray log which may be used according to
some embodiments of the present disclosure. Other gamma-ray logs
may also be used including open-hole logs, cased-hole logs, logs
performed by drilling & measurement operations, wireline
operations, or any type of operation that my result in creation of
log showing the degree of radiation emanating from the wellbore
walls vs depth of or location along the wellbore. Determining the
location of a tubular string or other downhole component in a
wellbore 310 will now be discussed in relation to FIGS. 4A, 4B, 5,
6, 7A, and 7B.
[0035] Turning to FIGS. 4A and 4B, if the radioactive source 400 is
an artificial source, such as a radioactive pip-tag, the artificial
radioactive source may be placed in the casing during a casing
cementing operation. The radioactive source 400 may be located at a
generally known position according to the TD and SD, which position
may be determined during a wireline cement logging operation
typically performed during cementing operations of the wellbore.
Radioactive pip-tags are generally formation markers placed into
casing cement at pre-determined intervals along the wellbore 310
when the wellbore is cased. Some wellbores may have multiple
radioactive sources 400 located along the wellbore wall, as shown
in FIGS. 4A and 4B.
[0036] If the radioactive source 400 is a natural radioactive
source, the natural background radiation, such as gamma-ray
radiation, emanates from the formation 311 forming the wellbore 310
and through any casing and cement present. In the situations
utilizing the natural radioactive source, the radioactive source
400 shown in the Figures depicts locations along the wellbore 310
that have higher intensities of background radiation. For example,
FIGS. 7A and 7B show an open-hole gamma-ray log with sufficient
variation to provide a radiation intensity signature, such as
between 565 and 570 meters downhole in FIG. 7A and 615 and 620
meters downhole in FIG. 7B.
[0037] In some embodiments, the method includes placing a tubular
string 315 into a wellbore 310 having at least one radioactive
source 400, as shown in box 502. The tubular string 315 has at
least one depth measurement module 120, as shown in box 502 and
FIGS. 4A-4B. The depth measurement module 120 was previously
described and shown in FIG. 2. In some embodiments, two or more
depth measurement modules 120 may be provided along the tubular
string 315. The depth measurement modules 120 are spaced apart
along the tubular string 315 at known distances, which known
distance can also be used to correlate the position of the depth
measurement modules, and thus the location in the wellbore of
various tools that are part of the tubular string 315.
[0038] A wellbore property that is a function of depth is
determined, as shown in box 504. In some embodiments, a plurality
of wellbore property measurements are obtained wherein at least one
wellbore property is a function of depth. In one example, the
plurality of wellbore property measurements may be obtained by
measuring a wellbore property with the depth measurement module 120
at a plurality of locations in the wellbore 310. One of the
locations in the wellbore 310 may be at the radioactive source 400.
Generally, the plurality of locations where a measurement of a
wellbore property is taken may include locations above the
radioactive source 400, such as position A, at the radioactive
source 400, such as position B, and below the radioactive source
400, such as position C. Measurements may be taken at multiple
locations along the wellbore, either discretely or continuously.
Wellbore property measurements may also be obtained during an RIH
operation (where the tubular string is run in the hole) or a POOH
operation (when the tubular string is pulled out of the hole).
[0039] The wellbore property that is measured is a function of
depth. Some examples of downhole parameters or wellbore properties
that are a function of depth may include pressure, temperature,
density, gravity, and acceleration. For purposes of this
discussion, pressure will be used as a specific example of wellbore
properties that are a function of depth, although other wellbore
properties that are a function of depth may be equally effective.
The sensors 202 in depth measurement module 120 may include sensors
for sensing the wellbore property, such as pressure or temperature
sensors. The sensors 202 also include a radiation sensor for
measuring the intensity of nearby radiation, in order to determine
a plurality or radiation intensities, as shown in box 506, or
obtain a plurality of radiation intensity measurements. The
wellbore property and radiation intensity measurements taken along
the wellbore as the tubular string is extended into or out of the
wellbore may be correlated with each other and the total time used
to obtain the measurements. One such correlation is shown in FIG.
6, which is described below in more detail.
[0040] Measuring the wellbore property with the depth measurement
module 120 may include measuring the wellbore property at a first
location A above the radioactive source 400, which first
measurement may be termed DP.sub.start. The wellbore property may
also be measured at a second location B when the depth measurement
module 120 is at the radioactive source 400 such as a pip-tag,
which second measurement may be termed DP.sub.pip. The wellbore
property may also be measured at a third location C in the wellbore
below the radioactive source 400, which third measurement may be
termed DP.sub.end. The radioactive source 400 may be located at a
known distance Z.sub.0 from the zone of interest 308.
[0041] If pressure is chosen as the wellbore property to be
measured, the three different measurements in this example may be
termed P.sub.start, P.sub.pip, P.sub.end. Additionally, the
wellbore property may be continuously measured as the depth
measurement module 120 moves up and down the wellbore 310, such as
shown in the graph illustrated in FIG. 6. Likewise, more than one
wellbore property that is a function of depth may be measured at
the same time using multiple types of sensors with the depth
measurement module 120, such as pressure and temperature.
[0042] Determining the change in length of the tubular string 315
as it is extended or extracted from the wellbore in order to obtain
the wellbore property that is a function of depth and the radiation
intensity at at least one location is optional, as shown in dashed
box 508. This change in length, which may be termed length change
L.sub..DELTA., is the change in tubular string length utilized to
obtain the plurality of downhole measurements along the wellbore.
The length change L.sub..DELTA. of the tubular string 315 is the
difference in tubular string lengths at various downhole
measurement locations along the wellbore, such as the difference of
the tubular string length at DP.sub.start and DP.sub.end.
[0043] In one example, the length change, L.sub..DELTA., is the
length L.sub.in of the tubular string 315 that is introduced into
the wellbore in order to measure the wellbore property at the
plurality of locations. Determining the length L.sub.in may be
performed in various ways. In one example, the length L.sub.in may
be determined by measuring a first distance, h.sub.1, from a rig
floor 302 to a top of the tubular string 315 when the depth
measurement module 120 is at the first location "A" in the wellbore
310. Another option is to measure the length L.sub.out that is
extracted from the wellbore as the tubular string 315 is pulled out
of the wellbore and wellbore property measurements are obtained
during the pull out procedure. Any known methods of determining the
length change L.sub..DELTA., of the tubular string 315, whether it
is L.sub.in or L.sub.out, during the wellbore property measurements
may be used.
[0044] After obtaining the first measurement such as pressure,
P.sub.start, one or more tubulars 410 of known length L may be
connected to the tubular string 315 and the tubular string 315 may
be lowered into the wellbore 310 to perform the second and third
measurements P.sub.pip and P.sub.end. The tubular 410 may be a
single drill pipe, tubing section, or a stand, which stand is
typically formed by connecting together three drill pipes or tubing
sections prior to connecting the stand to the tubular string.
Made-up stands may be stored on the drill rig site, ready for
connecting to the drill string. After the wellbore property
measurements are complete, a second distance, h.sub.2, from the rig
floor 302 to the top of the tubular string 315 is measured when the
tubular string 315 is at the third location C.
[0045] Knowing the location or depth in the wellbore where each
wellbore property measurement is taken can be determined by using a
correlation between the radiation intensity, which intensity is
determined and/or measured with the radiation sensor disposed in
the depth measurement module 120 during measurement of the wellbore
property at the plurality of locations, and the measured wellbore
properties. FIG. 6 illustrates a graph of the measured wellbore
property and radiation intensity vs time. In this example, the
measured wellbore property is pressure and the radiation is
gamma-ray type radiation. Two different measurements of radiation
intensity are shown, line 610 illustrating measurement of a single
radioactive source placed in the wellbore, and dashed line 620
illustrating measurement of a plurality of radioactive sources
placed in the wellbore.
[0046] Beginning with line 610, at a time t.sub.start, the pressure
P.sub.start is measured at a first location A in the wellbore 310.
The tubular string 315 is lowered into the wellbore 310. The
pressure and gamma-ray intensity may be continuously or
discontinuously (discreetly) measured as the tubular string is run
in the hole (RIH). The gamma-ray intensity peaks at time t.sub.pip
at the second location B when the depth measurement module 120 is
at the same depth as the radioactive source 400, such as a pip-tag.
The pressure at time t.sub.pip is measured, which corresponds to
P.sub.pip. The depth measurement module 120 passes by the
radioactive pip-tag as the tubular string 315 continues to be
lowered into the wellbore 310. Extension of the tubular string 315
into the wellbore 310 is stopped at time t.sub.end, and the
pressure at that location in the wellbore is measured, which
corresponds to P.sub.end. The wellbore property measurements and
radiation intensity data from the radiation sensor may be
transmitted via the telemetry device 208 up the tubular string 313
and to the wellbore surface system 58, as shown in FIG. 1.
[0047] Line 620 illustrates measurement of a plurality of
radioactive sources that are placed in the wellbore at known
locations. For example, three radioactive sources may be placed at
set intervals a part from each other along the wellbore 310, such
as one meter apart. The plurality of radioactive sources 400 then
form a known pattern of measured radiation intensity, thereby
providing a radiation intensity signature indicating that the depth
measurement module is at a known location along the wellbore. The
radioactive sources may have varying radiation intensities, giving
a cluster of radiation measurement peaks that form the known
pattern. For example, as shown in line 620, the middle radioactive
source measured at time t.sub.pip may have lower radiation
intensity than the neighboring radioactive sources, measured at
times t.sub.pip-1 and t.sub.pip+1. Providing a radiation
measurement signature may further decrease time for obtaining the
desired location as the known pattern indicating the location
signature may be quicker for operators to discern than radiation
measurement patterns measured from a single radioactive source.
Alternatively, if the natural background radiation is utilized, the
known pattern of measured radiation intensity may be provided by
the gamma-ray logs as shown in FIGS. 7A and 7B. The cluster of
radiation peaks and valleys which provide sufficient variation,
thereby forming a characteristic signature of radiation
intensity.
[0048] Once the wellbore property and radiation intensity have been
determined, the location of the depth measurement module 120 in the
wellbore 310 may be determined based on a correlation of the
wellbore property that is a function of depth and the radiation
intensity at at least one location within the wellbore, as shown in
box 510. Optionally, the length change L.sub..DELTA. of the tubular
string in the wellbore utilized in order to determine the wellbore
property and radiation intensity at at least one location within
the wellbore 310 may be included in the correlation between the
wellbore property and the radiation intensity used to determine the
location of the depth measurement module in the wellbore 310. In
situations where more than one depth measurement module 120 is
provided along the tubular string 315, the correlation may also
include the radiation intensities and wellbore properties
determined by the two measurement modules 120 and the known
distance along the tublar string 315 between the two measurement
modules.
[0049] The plurality of wellbore property measurements may include
P.sub.start, P.sub.pip, P.sub.end. The radiation intensity at those
corresponding locations where the wellbore property measurements
were obtained may include a continuous radiation intensity
measurement as shown in FIG. 6. The length change L.sub..DELTA. of
the tubular string in the wellbore may include length L.sub.in of
drill string 315 introduced into the wellbore 310. For example,
determining a distance travelled by the tubular string 315 into the
wellbore may be based on a correlation of h.sub.1, h.sub.2, L, and
the measured wellbore properties at the first, second, and third
locations, DP.sub.start, DP.sub.pip, DP.sub.end.
[0050] Using pressure as an example, we can determine the depth and
location of the depth measurement module 120 using the following
equations. The total length of tubular string introduced may be
calculated according to the following formula:
L.sub.in=h.sub.1+L-h.sub.2
A rough idea of the density is known in the wellbore before a
desired operation is performed, such as perforation. Therefore, an
estimated value of the pressure can be calculated at any depth
using the hydrostatic pressure law:
P=.rho.gh
Once the total length L.sub.in is determined, the location or depth
in the wellbore 310 of the depth measurement module 120 may be
determined using the hydrostatic pressure law according to the
following formula:
.DELTA. P = .rho. L g cos .alpha. .DELTA. z -> .rho. L cos
.alpha. = .DELTA. P g .DELTA. z = 1 g P end - P start L in ( Eq . 1
) Thus : z 1 = P end - P pip .rho. L g L cos .alpha. = L in P end -
P pip P end - P start z 1 = ( h 1 + L - h 2 ) P end - P pip P end -
P start ( Eq . 2 ) ##EQU00001##
where Z.sub.1 is the depth of the depth measurement module 120 in
the wellbore. For Eq. 2 to be effective, the density; gravity, and
tubing deviation are assumed to be constant or nearly constant with
an acceptable amount of error introduced.
[0051] The wellbore property measurements may also be taken in
reverse order as well, such as at location C first, location B
second, and location A last, such as may be done while obtaining
wellbore property measurements while pulling the tubular string out
of the wellbore.
[0052] When extracting the tubular string 315 from the wellbore
310, one or more tubulars 410 of known length L may be disconnected
from the tubular string 315 after measuring a first distance,
h.sub.1, from a rig floor to a top of the tubular string when the
depth measurement module is at location C in the wellbore below the
pip-tag. A wellbore property at location C is measured, termed
DP.sub.start, using the depth measurement module. The tubular
string 315 is then extracted from the wellbore 310, and the
wellbore property is measured at a second location B when the depth
measurement module 120 is at the radioactive pip-tag, DP.sub.pip.
The method also includes measuring the wellbore property at a third
location A in the wellbore above the pip-tag, DP.sub.end, and
measuring a second distance, h.sub.2, from the rig floor to the top
of the tubular string when the tubular string is at the third
location C. The method also includes determining the location of
the depth measurement module in the wellbore based on a correlation
of h.sub.1, h.sub.2, L, and the measured wellbore properties at the
first, second, and third locations, DP.sub.start, DP.sub.pip, and
DP.sub.end.
[0053] By using embodiments of the present disclosure, the rate at
which the tubing string is run into the hole does not need to be
constant. Additionally, the depth location process may include
multiple iterations where measuring the wellbore property at the
plurality of locations and the determining the length, L.sub.in, of
the tubular string 310 introduced into the wellbore when performing
the wellbore property measurements is repeated. Then, determining
the location or depth of the depth measurement module 120 based on
the repeated measuring and determining processes is performed
again. Iterating the process for determining the location or depth
of the module 120 may be particularly beneficial to increase
accuracy. Moreover, the depth measurement module may be
repositioned to a desired wellbore location based on its determined
location. For example, if the location of the depth measurement
module and hence the tubing string is determined to be in the
incorrect desired location, but at a known incorrect location or
depth, the tubing string may be raised or lowered by an amount
calculated to place the depth measurement module and tubing string
in the desired location based on its current incorrect location or
depth.
[0054] Although some of the examples described herein review
wellbore property measurements taken as the tubular string 315 is
RIH, similar data could be collected and transmitted at multiple
locations within the wellbore 310 and in various sequences, such as
when the tubular string is pulled out of the hole (POOH).
[0055] Although the preceding description has been described herein
with reference to particular means, materials and embodiments, it
is not intended to be limited to the particulars disclosed herein;
rather, it extends to all functionally equivalent structures,
methods, and uses, such as are within the scope of the appended
claims.
* * * * *