U.S. patent application number 12/628622 was filed with the patent office on 2010-06-10 for system and method for monitoring volume and fluid flow of a wellbore.
This patent application is currently assigned to BAKER HUGHES INCORPORATED. Invention is credited to Michael R. Taylor.
Application Number | 20100139386 12/628622 |
Document ID | / |
Family ID | 42229572 |
Filed Date | 2010-06-10 |
United States Patent
Application |
20100139386 |
Kind Code |
A1 |
Taylor; Michael R. |
June 10, 2010 |
SYSTEM AND METHOD FOR MONITORING VOLUME AND FLUID FLOW OF A
WELLBORE
Abstract
An apparatus for estimating a parameter of a borehole disposed
in an earth formation, the system includes: an injection unit
configured to inject at least one radio frequency identification
device (RFID) into a fluid configured to be disposed in the
borehole; and a collection unit configured to receive at least a
portion of the fluid, the collection unit comprising a detector
that detects at least one of the at least one RFID and data
contents thereof; wherein the detector provides output for
estimating the parameter. A method for estimating a parameter of a
borehole is also disclosed.
Inventors: |
Taylor; Michael R.;
(Calgary, CA) |
Correspondence
Address: |
CANTOR COLBURN LLP- BAKER HUGHES INCORPORATED
20 Church Street, 22nd Floor
Hartford
CT
06103
US
|
Assignee: |
BAKER HUGHES INCORPORATED
Houston
TX
|
Family ID: |
42229572 |
Appl. No.: |
12/628622 |
Filed: |
December 1, 2009 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61119843 |
Dec 4, 2008 |
|
|
|
Current U.S.
Class: |
73/152.23 ;
73/152.18 |
Current CPC
Class: |
E21B 47/003 20200501;
E21B 47/11 20200501 |
Class at
Publication: |
73/152.23 ;
73/152.18 |
International
Class: |
E21B 49/08 20060101
E21B049/08; E21B 47/10 20060101 E21B047/10 |
Claims
1. An apparatus for estimating a parameter of a borehole disposed
in an earth formation, the system comprising: an injection unit
configured to inject at least one radio frequency identification
device (RFID) into a fluid configured to be disposed in the
borehole; and a collection unit configured to receive at least a
portion of the fluid, the collection unit comprising a detector
that detects at least one of the at least one RFID and data
contents thereof; wherein the detector provides output for
estimating the parameter.
2. The apparatus of claim 1, further comprising a processor in
operable communication with at least one of the injection unit and
the detector, the processor configured to calculate a circulation
time between injection of the at least one RFID into the borehole
fluid and detection of the at least one RFID by the detector and to
calculate a volume of the borehole.
3. The apparatus of claim 1, wherein the collection unit is located
at a surface location.
4. The apparatus of claim 1, wherein the at least one RFID is a
plurality of RFIDs.
5. The apparatus of claim 4, wherein each RFID in the plurality is
a microelectromechanical system (MEMS) device.
6. The apparatus of claim 4, wherein each RFID in the plurality is
configured to emit a unique identification signal to the
detector.
7. The apparatus of claim 1, wherein the injection unit is disposed
in at least one of a surface location and a downhole location.
8. The apparatus of claim 1, further comprising a bottomhole
assembly (BHA) including a drill bit assembly, the bottomhole
assembly incorporating the injection unit therein.
9. The apparatus of claim 1, wherein the parameter is an annular
volume between a borehole assembly and the borehole, the borehole
assembly being configured to be disposed along a length of the
borehole and to receive the fluid therein.
10. The apparatus of claim 1, further comprising a return conduit
located at a surface location and in fluid communication with an
annular portion of the borehole.
11. The apparatus of claim 10, wherein the collection unit forms a
selected portion of the return conduit and the detector is disposed
on the selected portion.
12. The apparatus of claim 1, wherein the collection unit comprises
an antenna and an electronics unit configured to emit an
electromagnetic detection signal into the collection unit.
13. The apparatus of claim 12, wherein the at least one RFID
comprises a processing unit and an antenna configured to receive
the detection signal and emit a return signal identifying the at
least one RFID and data contents thereof.
14. A method of estimating a parameter of a borehole disposed in an
earth formation, the method comprising: injecting at least one
radio frequency identification device (RFID) in a fluid configured
to be disposed in the borehole; circulating the fluid through the
borehole and receiving at least a portion of the fluid in a
collection unit; detecting at least one of the at least one RFID
and data contents thereof with a detector in the collection unit;
and providing output from the detector for estimating the
parameter.
15. The method of claim 14, further comprising introducing a
drillstring into the borehole and introducing the fluid into the
drillstring.
16. The method of claim 15, wherein circulating comprises
circulating the fluid through the drillstring and the borehole.
17. The method of claim 14, further comprising measuring a
circulation time between injecting the at least one RFID and
detecting the at least one RFID and estimating a volume of the
borehole using the circulation time.
18. The method of claim 17, wherein the volume is an annular volume
between the drillstring and the borehole.
19. The method of claim 14, wherein the at least one RFID device is
injected at a location selected from at least one of a surface
location and a downhole location.
20. The method of claim 14, wherein the collection unit is in fluid
communication with a return conduit located at a surface location
and in fluid communication with an annular portion of the
borehole.
21. The method of claim 20, wherein the detector is disposed on a
portion of the return conduit.
22. The method of claim 14, wherein the detecting comprises
emitting an electromagnetic detection signal into the collection
unit and causing the at least one RFID device to emit a return
signal for identifying at least one of the at least one RFID and
the data contents thereof.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of an earlier filing
date from U.S. Provisional Application Ser. No. 61/119,843 filed
Dec. 4, 2008, the entire disclosure of which is incorporated herein
by reference.
BACKGROUND
[0002] During hydrocarbon drilling and recovery operations, a
drilling fluid is injected into a drillstring as a wellbore is
drilled through an earth formation or through pre-existing
equipment installed in that borehole. The drilling fluid or "mud"
circulates through the drillstring, exiting through orifices, also
known as "nozzles" or "jets", into the wellbore annulus. That
drilling fluid then passes from the bottom of the hole or exit
point through the wellbore annulus between the wall of the hole and
the outside diameter of the drillstring and then onwards to the
surface where the returning fluid is recovered for treatment or
disposal.
[0003] Material cut from the formation during drilling, known as
drill cuttings, can be evaluated to determine various
characteristics of the discreet layers of the formation being
penetrated, such as lithology, mineralogy including trace minerals,
fossil or other organic content, petrophysical & geophysical
characteristics, as well as any residual hydrocarbon, gas, or other
fluid contents trapped in the pore space of the formation. In
addition, the destruction of the formation by the drill bit or
other drilling and hole enlarging tools results in the pore
contents of the formation being released into the mud as "mud gas".
Mud gas may be in liquid form under downhole pressure and
temperature conditions, but the liquid form may change to gaseous
form during the transition from the wellbore annulus to the
atmospheric conditions at the surface. Examples of "mud gas"
include hydrocarbons, such as the alkanes including methane,
ethane, propane and others; "acidic" gases such as carbon dioxide
and hydrogen sulphide; and noble gases such as helium, nitrogen,
argon, etc. Other fluids trapped in the pore spaces of the
formation such as oil and water, which may contain salts such as
chlorides, may influence characteristics such as other chemical
components, temperature, pressure, weight and viscosity of the mud.
Such evaluation of solids, liquids, gases and mud conditions is
generally referred to as "mud logging".
[0004] The volume of the wellbore annulus varies continuously while
drilling progresses due to planned and incidental variations in
wellbore diameter, changes in the drillstring configuration and its
external diameters and lengths. The time to displace the contents
of the wellbore annulus varies by the volumetric rate and location
at which fluid is pumped into the drillstring, the quantity exiting
the well and returning to the surface systems, the mud type and
conditions, and any interactions between the solids, liquids and
gases from the formations penetrated or exposed in the wellbore,
and the drilling fluid used to drill or complete the well. The
individual times for solids, liquids and gases being displaced in a
wellbore further varies by the density, shape, and surface and
physio-chemical characteristics of the formation and the contents
of its pore spaces.
[0005] Mud logging requires accurate knowledge of the annular
volume in a wellbore in order to accurately reconstruct the
lithological and formation fluid components at the drill bit, based
on samples which are recovered over time from the drilling fluid at
the surface. One method of quantifying the annular volume involves
the use of "tracers", i.e., non-reactive and detectable alien
material inserted into the drilling fluid at the surface during a
pumping operation. The tracer is moved from the drillstring annulus
into the wellbore annulus and then returns to the surface where it
detected and/or recovered.
[0006] Current tracer technology involves adding a quantity of
calcium carbide in the form of a "pill" that reacts to form
acetylene in contact with water, or adding a stream of acetylene or
similar detectable alien gas, fluid or solid to the drilling fluid.
The tracer is added at the surface, and its return is identified
using a mud logging gas detection system or other sensors installed
at the surface and in contact with the drilling fluid. An annular
volume is estimated from the time duration between injector to
detector, and the resultant volume displaced by the mud pumps
during that duration. The tracers may be recycled over several
displacements of the annular volume until they become undetectable.
However, this technique offers potential confusion about which
tracers are actually being detected, compromising the accuracy of
the volume estimate.
SUMMARY
[0007] Disclosed is an apparatus for estimating a parameter of a
borehole disposed in an earth formation, the system includes: an
injection unit configured to inject at least one radio frequency
identification device (RFID) into a fluid configured to be disposed
in the borehole; and a collection unit configured to receive at
least a portion of the fluid, the collection unit comprising a
detector that detects at least one of the at least one RFID and
data contents thereof; wherein the detector provides output for
estimating the parameter.
[0008] Also disclosed is a method of estimating a parameter of a
borehole disposed in an earth formation, the method includes:
injecting at least one radio frequency identification device (RFID)
in a fluid configured to be disposed in the borehole; circulating
the fluid through the borehole and receiving at least a portion of
the fluid in a collection unit; detecting at least one of the at
least one RFID device and data contents thereof with a detector in
the collection unit; and providing output from the detector for
estimating the parameter.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] The following descriptions should not be considered limiting
in any way. With reference to the accompanying drawings, like
elements are numbered alike:
[0010] FIG. 1 depicts an embodiment of a well logging and/or
drilling system;
[0011] FIG. 2 is a flow chart providing an exemplary method of
measuring a fluid volume through a borehole; and
[0012] FIG. 3 is an illustration of a system for measuring a fluid
volume through a borehole.
DETAILED DESCRIPTION OF THE INVENTION
[0013] Referring to FIG. 1, an exemplary embodiment of a well
logging and/or drilling system 10 includes a drillstring 11 that is
shown disposed in a borehole 12 that penetrates at least one earth
formation 14 during a drilling, well logging and/or hydrocarbon
production operation. The drillstring 11 includes a drill pipe,
which may be one or more pipe sections or coiled tubing. The well
drilling system 10 also includes a bottomhole assembly (BHA) 18. A
borehole fluid 16 such as a drilling or completion fluid or
drilling mud may be pumped through the drillstring 11, the BHA 18
and/or the borehole 12. The drilling or completion fluid is liquid
and/or gaseous.
[0014] As described herein, "borehole" or "wellbore" refers to a
single hole that makes up all or part of a drilled well. As
described herein, "formations" refer to the various features and
materials that may be encountered in a subsurface environment.
Accordingly, it should be considered that while the term
"formation" generally refers to geologic formations of interest,
that the term "formations," as used herein, may, in some instances,
include any geologic points or volumes of interest (such as a
survey area). Furthermore, various drilling or completion service
tools may also be contained within this borehole or wellbore, in
addition to formations. In addition, it should be noted that
"drillstring" as used herein, refers to any structure suitable for
lowering a tool through a borehole or connecting a drill bit to the
surface, and is not limited to the structure and configuration
described herein. For example, the drillstring 11 is configured as
a hydrocarbon production string.
[0015] In one embodiment, the BHA 18 includes a drilling assembly
having a drill bit assembly 20 and associated motors adapted to
drill through earth formations. In one embodiment, the drill bit
assembly 20 includes a steering assembly including a steering motor
22 configured to rotationally control a shaft 24 connected to a
drill bit or drilling tool 26. The shaft is utilized in drilling
and milling operations to steer the drill bit 26 and the
drillstring 11 through the formation 14 or through pre-existing
drilling or completion service tools.
[0016] During drilling operations, the drilling fluid 16 is
introduced into the drillstring 11 from a mud tank or "pit" 28 or
other source of drilling fluid 16, which may be liquid and/or
gaseous, and is circulated under pressure through the drillstring
11, for example via one or more mud pumps. The drilling fluid 16
passes into the drillstring 11 and is discharged at the bottom of
the borehole through an opening in the drill bit or drilling tool
26. The drilling fluid 16 circulates uphole between the drill
string 11 and the borehole 12 and is discharged into, for example,
the mud tank 28 via a return flow line 30.
[0017] The system 10 includes a tracer system for calculating a
circulation time of the drilling fluid 16 through the borehole 12,
which is in turn utilized to calculate the fluid volume. In one
embodiment, an effective volume of the drillstring 11 and the
borehole 12 is calculated using the time duration taken from
injection to detection and the volume displaced by the mud pumps
during that duration. As used herein, the fluid may include
drilling fluid 16 which may be liquid or gaseous, as well as any
combination of gases, hydrocarbons and cuttings or millings from
the drill bit and the formation 14, and is accordingly referred to
hereafter as "borehole fluid" 16.
[0018] The tracer system includes an injection unit 32 including at
least one Radio Frequency Identification Device ("RFID") 34. The
RFID 34 has known characteristics and may potentially be a
plurality of RFIDs of the same or different sizes. The injection
unit 32, in one embodiment, is disposed at a surface location, such
as in fluid communication with a suction tank included in a
drilling rig connected to the drillstring 11. In other embodiments,
the injection unit 32 is configured to inject the RFID 34 at any
selected location along the length of the drillstring 11.
[0019] In one embodiment, the RFID 34 is in the nano-scale. In
another embodiment, the RFID 34 is a microelectromechanical system
device ("MEMS") incorporated in a MEMS system. For example, a MEMS
system includes a plurality of MEMS devices each incorporating an
RFID 34. Such MEMS particles are referred to as "smart dust". Using
a plurality of RFIDs 34, such as in a smart dust system, with
different signatures and particle sizes enables a more complete
annular profile and displacement rates to be mapped.
[0020] In one embodiment, the MEMS devices are sensors configured
to measure physico-chemical properties of the drillstring 11, the
borehole 12 and/or the formation 14, and carry data corresponding
to these properties to a surface detection system. Examples of such
physico-chemical properties include pressure, temperature and
chemical composition.
[0021] In one embodiment, the MEMS devices or smart dust are
incorporated into a fluid additive configured to be injected into a
drilling or completion fluid or other borehole fluid. In this
embodiment, the smart dust is included in the fluid additive prior
to injection into the borehole fluid.
[0022] The tracer system further includes a collection unit 36 that
receives at least a portion of the borehole fluid 16. A detector 38
is disposed within the collection unit 36 and includes an antenna
and suitable electronics to emit an electromagnetic detection
signal into the borehole fluid 16. In one embodiment, the detector
38 is disposed at any suitable location, such as on the return flow
line 30. In this embodiment, the collection unit 36 forms a portion
of the return flow line 30, and the detector detects the RFID 34 as
it passes through the return flow line 30.
[0023] Each RFID 34 includes a processing chip or other electronics
unit and an antenna configured to receive the detection signal and
emit a return signal identifying the RFID 34. For example, each
RFID 34 is programmed with a unique identification number or batch
number that is sent to the detector 38 in the return signal. The
data associated with the return signal, in one embodiment, is
transmitted to a suitable processor such as a surface processing
unit 40. The processor identifies the detected RFID 34, calculates
a circulation time from the difference between the time that the
RFID 34 is injected into the drilling fluid 16 and the time that
the RFID 34 is detected.
[0024] In one embodiment, the tracer system and/or the BHA 18 are
in communication with the surface processing unit 40. In one
embodiment, the surface processing unit 40 is configured as a
surface drilling control unit which controls various production
and/or drilling parameters such as rotary speed, weight-on-bit,
fluid flow parameters, pumping parameters and others and records
and displays real-time drilling performance and/or formation
evaluation data. In addition, the surface processing unit may be
configured as a tracer system control unit and control the
injection of the RFID 34 remotely. The BHA 18 and/or the tracer
system incorporates any of various transmission media and
connections, such as wired connections, fiber optic connections,
wireless connections and mud pulse telemetry.
[0025] In one embodiment, the surface processing unit 40 includes
components as necessary to provide for storing and/or processing
data collected from the injection unit 32 and/or the collection
unit 36. Exemplary components include, without limitation, at least
one processor, storage, memory, input devices, output devices and
the like.
[0026] The BHA 18, in one embodiment, includes a downhole tool 42.
In one embodiment, selected components of the tracer system are
incorporated into the downhole tool 42, such as the injection unit
32, to allow the travel time of the fluid between the drill bit
assembly 20 and the surface to be calculated.
[0027] In one embodiment, the downhole tool 42 includes one or more
sensors or receivers 44 to measure various properties of the
borehole environment, including the formation 14 and/or the
borehole 12. Such sensors 44 include, for example, nuclear magnetic
resonance (NMR) sensors, resistivity sensors, porosity sensors,
gamma ray sensors, seismic receivers and others. Such sensors 44
are utilized, for example, in logging processes such as
measurement-while-drilling (MWD) and logging-while-drilling (LWD)
processes.
[0028] Although the tracer system is described in conjunction with
the drillstring 11, the tracer system may be used in conjunction
with any structure suitable to be lowered into a borehole, such as
a production string or a wireline.
[0029] FIG. 2 illustrates a method 50 of measuring a fluid volume
through a borehole. The method 50 is used in conjunction with the
tracer system and the surface processing unit 40, although the
method 50 may be utilized in conjunction with any suitable
combination of processors and systems incorporating RFID devices.
The method 50 includes one or more stages 51, 52, 53, 54 and 55. In
one embodiment, the method 50 includes the execution of all of
stages 51-55 in the order described. However, certain stages may be
omitted, stages may be added, or the order of the stages
changed.
[0030] In the first stage 51, the drillstring 11 is introduced into
the borehole 12 and borehole fluid 16 is introduced into the
drillstring 11.
[0031] In the second stage 52, at least one RFID 34 is injected
into the borehole fluid 16 from the injection unit 32. A location
and time of the injection is noted and, in one embodiment,
transmitted to a suitable processor.
[0032] In the third stage 53, the borehole fluid 16 is circulated
through the drillstring 11 and returns to the surface through the
borehole 12. A portion of the borehole fluid 16 is collected by the
collection unit 36. At this point, the borehole fluid 16 may
include drill bit cuttings, water, gas, hydrocarbons, formation
material and/or other materials.
[0033] In the fourth stage 54, the RFID 34 is detected in the
collection unit 36. In one embodiment, the time of detection is
noted and transmitted to the processor.
[0034] In the fifth stage 55, a circulation time between injecting
the at least one RFID 34 and detecting the at least one RFID 34 is
calculated, and a borehole fluid volume is calculated based on the
circulation time. This volume may include the volume of fluid
within the drillstring 11 and/or the annular volume of fluid
between the drillstring 11 and the walls of the borehole 12. For
example, if the flow rate of fluid introduced into the borehole 12
is known, such as the volumetric flow of fluid through a mud pump,
the circulation time of the RFID 34 is used to determine a total
fluid volume in the borehole 12.
[0035] Referring to FIG. 3, there is provided a system 60 for
measuring the time taken for a fluid volume to be displaced through
a borehole and/or calculating a volume of the drillstring 11 and/or
the wellbore 12. The system may be incorporated in a computer 61 or
other processing unit capable of receiving data from the injection
unit 32 and/or the detector 38. Exemplary components of the system
60 include, without limitation, at least one processor, storage,
memory, input devices, output devices and the like. As these
components are known to those skilled in the art, these are not
depicted in any detail herein.
[0036] Generally, some of the teachings herein are reduced to
instructions that are stored on machine-readable media. The
instructions are implemented by the computer 61 and provide
operators with desired output.
[0037] The systems and methods described herein provide various
advantages over prior art techniques. In contrast to calcium
carbide tracers, the tracers described herein do not need to be
introduced on a well rig floor, and can rather be introduced into a
rig's suction tank or from downhole sources within the drillstring
or bottom hole assembly automatically and/or remotely without the
need for human manual intervention. In addition, tracers described
herein can be differentiated by size, physical characteristics or
electronic characteristics, eliminating any confusion as to which
tracers are being detected. These tracers may also be able to
measure and carry data to reflect the ambient environment through
which they have passed.
[0038] In support of the teachings herein, various analyses and/or
analytical components may be used, including digital and/or analog
systems. The system may have components such as a processor,
storage media, memory, input, output, communications link (wired,
wireless, pulsed mud, optical or other), user interfaces, software
programs, signal processors (digital or analog) and other such
components (such as resistors, capacitors, inductors and others) to
provide for operation and analyses of the apparatus and methods
disclosed herein in any of several manners well-appreciated in the
art. It is considered that these teachings may be, but need not be,
implemented in conjunction with a set of computer executable
instructions stored on a computer readable medium, including memory
(ROMs, RAMs), optical (CD-ROMs), or magnetic (disks, hard drives),
or any other type that when executed causes a computer to implement
the method of the present invention. These instructions may provide
for equipment operation, control, data collection and analysis and
other functions deemed relevant by a system designer, owner, user
or other such personnel, in addition to the functions described in
this disclosure.
[0039] Further, various other components may be included and called
upon for providing aspects of the teachings herein. For example, a
sample line, sample storage, sample chamber, sample exhaust,
filtration system, pump, piston, power supply (e.g., at least one
of a generator, a remote supply and a battery), vacuum supply,
pressure supply, refrigeration (i.e., cooling) unit or supply,
heating component, motive force (such as a translational force,
propulsional force or a rotational force), magnet, electromagnet,
sensor, electrode, transmitter, receiver, transceiver, controller,
optical unit, electrical unit or electromechanical unit may be
included in support of the various aspects discussed herein or in
support of other functions beyond this disclosure.
[0040] Elements of the embodiments have been introduced with either
the articles "a" or "an." The articles are intended to mean that
there are one or more of the elements. The terms "including" and
"having" and their derivatives are intended to be inclusive such
that there may be additional elements other than the elements
listed. The conjunction "or" when used with a list of at least two
terms is intended to mean any term or combination of terms.
[0041] One skilled in the art will recognize that the various
components or technologies may provide certain necessary or
beneficial functionality or features. Accordingly, these functions
and features as may be needed in support of the appended claims and
variations thereof, are recognized as being inherently included as
a part of the teachings herein and a part of the invention
disclosed.
[0042] While the invention has been described with reference to
exemplary embodiments, it will be understood by those skilled in
the art that various changes may be made and equivalents may be
substituted for elements thereof without departing from the scope
of the invention. In addition, many modifications will be
appreciated by those skilled in the art to adapt a particular
instrument, situation or material to the teachings of the invention
without departing from the essential scope thereof. Therefore, it
is intended that the invention not be limited to the particular
embodiment disclosed as the best mode contemplated for carrying out
this invention, but that the invention will include all embodiments
falling within the scope of the appended claims.
* * * * *