U.S. patent application number 14/802943 was filed with the patent office on 2015-11-12 for in-situ system calibration.
The applicant listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Mikko Jaaskelainen.
Application Number | 20150323700 14/802943 |
Document ID | / |
Family ID | 51221467 |
Filed Date | 2015-11-12 |
United States Patent
Application |
20150323700 |
Kind Code |
A1 |
Jaaskelainen; Mikko |
November 12, 2015 |
In-Situ System Calibration
Abstract
A method for re-calibrating installed downhole sensors used in
hydrocarbon wells by the application of a calibration string
inserted in the wells and deployed in close proximity to the
installed downhole sensor.
Inventors: |
Jaaskelainen; Mikko;
(Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Family ID: |
51221467 |
Appl. No.: |
14/802943 |
Filed: |
July 17, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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13751056 |
Jan 26, 2013 |
9121972 |
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14802943 |
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Current U.S.
Class: |
73/1.85 |
Current CPC
Class: |
G01K 15/005 20130101;
G01K 11/32 20130101; G01V 13/00 20130101 |
International
Class: |
G01V 13/00 20060101
G01V013/00 |
Claims
1. A downhole in-situ recalibration device for use in
re-calibrating an installed downhole seismic sensor comprising: a.
a downhole calibration string associated with seismic sensing; b.
wherein said calibration string contains a vibration source used to
apply a characteristic seismic signature on one or several downhole
points in close proximity to said installed downhole seismic
sensor.
2. The downhole in-situ recalibration device for use in
re-calibrating an installed downhole seismic sensor of claim 1
wherein the installed downhole seismic sensor is coupled to the
outside of a well casing and the downhole calibration string is
inserted into the wellbore.
3. The downhole in-situ recalibration device for use in
re-calibrating an installed downhole seismic sensor of claim 1
wherein the downhole calibration string is mechanically coupled to
the wellbore casing or tubing after insertion into the
wellbore.
4. The downhole in-situ recalibration device for use in
re-calibrating an installed downhole seismic sensor of claim 3
wherein the calibration string is mechanically coupled to the
wellbore casing or tubing by locking arms pressed against the
casing or tubing of the wellbore.
5. The downhole in-situ recalibration device for use in
re-calibrating an installed downhole seismic sensor of claim 3
wherein the calibration string is mechanically coupled by use of a
mechanical packer.
6. The downhole in-situ recalibration device for use in
re-calibrating an installed downhole seismic sensor of claim 3
wherein the calibration string is mechanically coupled by a
bow-spring device that expands to mechanically couple the
calibration string to the wellbore.
7. The downhole in-situ recalibration device for use in
re-calibrating an installed downhole seismic sensor of claim 1
wherein the characteristic seismic signature of the calibration
string has a known orientation.
8. A method for in-situ recalibration of an installed seismic
sensor in a downhole sensing system in hydrocarbon wells
comprising: a. Inserting a calibration string associated with
seismic sensing in the wellbore of the hydrocarbon well in close
proximity to said installed seismic sensor; wherein the calibration
string contains a vibration source that can be used to apply a
characteristic seismic signature on one or more downhole points in
close proximity to said installed downhole seismic sensor; b.
mechanically coupling the calibration string to the wellbore; c.
using the calibration string to apply characteristic signatures at
the one or more downhole points that are used to re-calibrate the
installed seismic sensor.
9. The method for in-situ recalibration of an installed seismic
sensor in a downhole sensing system in hydrocarbon wells of claim 8
wherein the calibration string is mechanically coupled to the
wellbore casing or tubing by locking arms pressed against the
casing or tubing of the wellbore.
10. The method for in-situ recalibration of an installed seismic
sensor in a downhole sensing system in hydrocarbon wells of claim 8
wherein the calibration string is mechanically coupled to the
wellbore casing or tubing by use of a mechanical packer.
11. The method for in-situ recalibration of an installed seismic
sensor in a downhole sensing system in hydrocarbon wells of claim 8
wherein the calibration string is mechanically coupled to the
wellbore casing or tubing by a bow-spring device that expands to
mechanically couple the calibration string to the wellbore.
12. The method for in-situ recalibration of an installed seismic
sensor in a downhole sensing system in hydrocarbon wells of claim 8
wherein the characteristic seismic signature of the calibration
string has a known orientation.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a divisional of U.S. application Ser.
No. 13/751,056 filed Jan. 26, 2013.
BACKGROUND
[0002] Fiber-optic sensors are increasingly being used as devices
for sensing some quantity, typically temperature or mechanical
strain, but sometimes also displacements, vibrations, pressure,
acceleration, rotations, or concentrations of chemical species. The
general principle of such devices is that light from a laser is
sent through an optical fiber and there experiences subtle changes
of its parameters either in the fiber or in one or several fiber
Bragg gratings and then reaches a detector arrangement which
measures these changes.
[0003] The growing interest in fiber optic sensors is due to a
number of inherent advantages: [0004] Inherently safer operation
(no electrical sparks) [0005] Immunity from EMI (electromagnetic
interference) [0006] Chemical passivity (not subject to corrosion)
[0007] Wide operating temperature range (wider than most electronic
devices) [0008] Electrically insulating (can be used in high
voltage environment)
[0009] Fiber optic sensors deployed in wells are predominately
calibrated before being deployed down hole. After calibration such
sensors are often permanently installed behind a well casing or
they are attached to the downhole tubing. As downhole conditions
change over time, some of these installed sensors may experience
high temperatures, high pressures and various chemicals that may
impact the installed sensor performance.
[0010] The sensor itself will often get calibration coefficients
that are unique to the sensor, and these calibration coefficients
are used in the interrogation unit to achieve desired accuracy and
resolution. Many sensors must periodically be calibrated due to
component drift either in the sensor itself or the interrogation
unit. In some cases, it is beneficial to calibrate the sensor and
the interrogation unit as a pair. Sensors permanently installed in
oil & gas wells cannot be removed for calibration, and
estimated annual drift requirements are applied to the sensing
system.
[0011] There are economic advantages to having a method for
re-calibrating such down-hole sensors. For example DTS systems are
usually calibrated with each fiber during or prior to deployment.
To replace a DTS system where you have up to 16 sensing
fibers/wells connected would be a challenging task due to the
calibration. The method proposed herein would allow in-situ
calibration of the DTS system and the sensing fiber in case the DTS
system or the fiber would need to be replaced.
[0012] Thus a need exists for ways to re-calibrate downhole sensing
systems in-situ, without having to remove the sensors from the
downhole environment.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] The foregoing issues are at least partly addressed by the
disclosed by the In-Situ System Calibration as illustrated in the
drawings. The drawings are not strictly to scale because the
calibration strings may be only 1-2 inches in diameter while
casings may be as small as 4 inches in diameter up to more than 16
inches.
[0014] FIG. 1(a) is an illustration of a calibration string for
calibration of a chemical sensor.
[0015] FIG. 1(b) is an illustration of an alternate embodiment of a
calibration string for calibration of a chemical sensor.
[0016] FIG. 2 is an illustration of a calibration string for
calibration of a strain sensor.
[0017] FIG. 3 is an illustration of a calibration string for
calibration of a pressure sensor.
[0018] FIG. 4 is an illustration of a double ended conduit with a
permanently installed optical fiber. The calibration string for
calibration of a Distributed Temperature Sensing (DTS) sensor may
be inserted in the right side tube (440).
[0019] FIG. 5 is an illustration of a calibration string for
calibration of a Distributed Acoustic Sensing (DAS) sensor.
[0020] FIG. 6 is an illustration of a calibration string for
calibration of a seismic sensor.
[0021] FIG. 7 is an illustration of a calibration string for
calibration of an electromagnetic sensing sensor.
DETAILED DESCRIPTION
[0022] In the following detailed description, reference is made
that illustrate embodiments of the present disclosure. These
embodiments are described in sufficient detail to enable a person
of ordinary skill in the art to practice these embodiments without
undue experimentation. It should be understood, however, that the
embodiments and examples described herein are given by way of
illustration only, and not by way of limitation. Various
substitutions, modifications, additions, and rearrangements may be
made that remain potential applications of the disclosed
techniques. Therefore, the description that follows is not to be
taken as limiting on the scope of the appended claims.
[0023] Modern fiber optic sensors are today being used in wells to
sense many different parameters including at least temperature,
pressure, strain, acoustic, seismic, electromagnetic, and chemical.
All of these sensors are calibrated prior to installation, and
permanently installed behind casing or attached to down-hole
tubing. Even in ideal conditions installed sensors must
periodically be calibrated due to component drift either in the
sensor itself or the interrogation unit. As down-hole conditions
change over time, some of these installed sensors may experience
high temperatures, high pressures and various chemicals that may
impact the sensor performance and increase the need for
re-calibration.
[0024] In the description to follow a method is proposed to
re-calibrate in-situ installed sensors by in each case inserting
in-situ recalibration devices which are usually calibration strings
associated with the particular installed sensors and inserted in
the well close to those sensors. The calibration string can be
permanently installed in the well, or it can be inserted for a
temporary logging operation. For each type of sensing system to be
described the calibration string is specifically associated with
the installed sensor system. The embodiments will be described in a
series of examples. The term calibration string, as used in this
description might be an inserted tube, such as a coiled tube, that
encloses the recalibration apparatus needed to recalibrate the
particular sensor that is installed in the well and may need
occasional recalibration. The term recalibration string can also be
a mechanical structure inserted downhole without need of any
tubing.
EXAMPLE 1
[0025] A chemical installed sensor is commonly impacted by repeated
exposure to down-hole chemicals such as for example wax, asphaltene
or other chemical commonly present down hole. These chemicals may
build up layers on top of the installed sensor element. A layer of
wax may change the performance of the sensor and in effect take the
installed sensor out of calibration.
[0026] For the chemical sensor system the calibration string may be
an inserted tubing. It can be equipped with one or several
reference chemical(s) that may be released down hole from the
calibration string and the system in order to re-calibrate the
installed chemical sensor. If the readings are off, a cleaning
solution can be released to remove wax, asphaltene and/or other
chemicals that may foul the chemical sensing interface and the
calibration routine can be repeated.
[0027] A chemical calibration string in a simple configuration is
shown in FIG. 1(a). A casing string 105, often backed by cement
100, is shown inside a formation 110. A permanently installed
sensor 140 is shown with a line 115 carrying electrical or optical
connectors running uphole to the surface. A small opening 142 in
the casing allows communication of the production fluids in the
casing with the permanently installed sensor. In this embodiment
the calibration string 120 is placed into the casing in close
proximity to permanently installed sensor 140 and may have one
injection point 130 to allow injection of fluid in the well bore.
In operation a known fluid is injected to clean the permanently
installed sensor, and the cleaning fluid is allowed to mix with the
production fluids. A second calibration liquid is then injected
down the calibration bore to calibrate the permanently installed
sensors. The calibration string may also have a reference chemical
sensor 125 connected (not shown) back to the surface.
[0028] A more precise calibration string may have packers 150
surrounding a calibration string 135 that may be inflated on
demand, as shown in FIG. 1(b). In this embodiment the calibration
string 135 is shown positioned inside of a casing 110 usually lined
with cement 100 and with inflatable packers 150 on each side of the
region in which the permanently installed chemical sensor 140 is
located. The permanent sensor 140 may be deployed behind casing and
may be cemented in place. A small opening 142 in the casing allows
communication of the production fluids in the casing with the
permanently installed sensor. In this embodiment calibration string
135 may also have more than one port to allow fluid circulation
from a first port 155 to a second port 160. There may be one 145 or
possibly more reference chemical sensors in the calibration string,
connected (not shown) back to the surface. One way of operating the
calibration string is to inflate 2 packers, one above and one below
the fluid ports and the reference sensor(s). Each of the ports 155
and 160 may have individual lines (not shown) running back to the
surface within calibration string 135 in order to feed and retrieve
the fluids to the desired area between packers 150. Cleaning and
calibration fluid can now be circulated between the fluid ports as
required to clean and calibrate the sensors. The packers can then
be deflated and the calibration string can be moved to a different
location.
[0029] The calibration string may have two packers and one fluid
injection port. The lower packer is then inflated and cleaning
fluid is pumped so that the fluid passes the permanently installed
sensor and cleans it. Calibrated fluid can then be pumped and the
second packer can be set once a selected volume has been pumped
into the area. The calibration fluid is now trapped between the
packers and both the permanently installed chemical sensor and the
reference sensor in the calibration string will be exposed to a
fluid with the same chemical concentration.
EXAMPLE 2
[0030] A strain sensing fiber must be coupled to the measurement
object for accurate measurements, and the sensing fiber must be
protected to avoid mechanical damage. This is normally achieved by
cabling the sensing fiber in a manner that the any strain in the
cable is communicated into the optical sensing fiber. The sensing
cable is then coupled to the measurement object by welding a
sensing cable to a structure, or gluing the sensing cable to a
structure, or by cementing the sensing cable in place. The sensing
fiber must be coupled to the sensing cable for accurate
measurements, and there may be creep between the sensing cable and
sensing fiber or creep between the sensing cable and the
measurement object. The creep depends on many different factors
like e.g. material selection, temperature, amount of strain the
sensing configuration is exposed to and this may change over time.
A strain sensor may experience significant mechanical exposure
during installation due to challenging well bore conditions, and
this may take the sensor out of calibration over time due to e.g.
creep as the tubing and/or casing may be left in tension, torsion
or compression.
[0031] For a strain sensor a mechanical system that can apply a
characteristic strain signature on one or several down-hole points
can be used to calibrate a strain sensing system. FIG. 2 shows such
an embodiment. A casing string 210 backed by cement 220 is shown
inside the formation 230. A calibration string 240, comprising a
central arm, may have one or several moveable arms 250 that extends
out from the calibration string and push against the walls of
casing or tubing 210. Both the casing and tubing may deform as the
mechanical arms push out onto the wall of the measurement object.
As the casing or tubing deforms, the resulting strain is captured
with the permanently installed strain sensor 260, which is cemented
behind casing 210. There could also be a single point strain sensor
265 deployed. The calibration string may have a strain sensing
system embedded in the tool or there may be point sensors in the
string to measure resulting strain on the tool. The system may have
pressure pads 270, 280 on the opposing side of the moveable arm to
generate a characteristic strain signature, and these pads may be
used instead of multiple moveable arms. The calibration string may
also include force-measuring pads on or in close proximity of the
moveable arms so that a strain can be calculated given that the
casing and tubing dimensions are well known in the well.
EXAMPLE 3
[0032] A fiber optic pressure installed sensor may experience creep
between the sensing fiber and the mechanical structure that
converts pressure to an optical property that can be sensed, and
this creep may take the installed sensor out of calibration. The
single point fiber optic pressure sensor of FIG. 3 may be installed
behind the casing and have a pressure port to communicate pressure
from inside the wellbore to the sensor. As shown in FIG. 3 a
permanently installed sensor 340 with electrical or optical
conductors 342 is shown behind casing 310 and is normally attached
to the measurement object by e.g. mechanical coupling, glued,
welded or cemented 305 in place along the length of the tubular
down-hole structure 310 such that any movement of the tubular
structure is coupled to the sensor.
[0033] This re-calibration can be done as follows. A calibration
string 335 with a pressure sensing system 345 using multiple
packers 350 can be used to isolate a zone where a permanently
installed pressure sensor 340 is installed. The packer(s) can be
used to isolate the zone, and the formation pressure can be used as
a calibration pressure and a comparison can be made between the
permanently installed sensor 340 and the reference pressure sensor
345 in the calibration string. The calibration string may have
means of applying a controlled pressure as well by applying
pressure via an opening 338 in the calibration string between the
packers.
[0034] A simple calibration string can be used without any packers
if formation pressure or tubing/casing pressure is used for
calibration. Depth correlation is normally done by measuring the
length of calibration string that has been lowered in the well. A
more accurate depth calibration can be done using permanently
deployed DTS and/or DAS combined with thermal and/or acoustic
events in the calibration string. An example of a thermal event
could be electrical heaters, fluid injection in the calibration
string where a difference in temperature is detected using the
permanently deployed DTS system. Examples of acoustic events could
be a battery operated device emitting a tone of a certain
frequency, and the location would be measured as the peak location
of the acoustic amplitude of the tone.
EXAMPLE 4
[0035] A Distributed Temperature Sensing (DTS) system may have
fiber-aging down-hole due to temperature and/or chemical exposure
causing inaccuracies in the measurements. This effect can largely
be mitigated in Distributed Temperature Sensing (DTS) systems using
dual laser technology, but re-calibration can in some cases improve
the accuracy of temperature readings.
[0036] This re-calibration can be done as follows. A calibration
string with means of measure temperature accurate can be inserted
into the wellbore for comparison between the permanently installed
sensor and the reference sensor. The calibration string may have
means of changing the down-hole temperature both for depth
calibration purposes and for temperature calibration purposes. The
temperature change can be made using electrical, chemical or
mechanical means like inserting fluid and/or steam through a
conduit in the calibration string. The calibration string could be
a well-calibrated optical fiber sensor pumped into a conduit, or a
small OD cable with optical fibers present. The calibration string
can also be a stiff cable that can be pushed into a conduit or
well. The reference sensor in the calibration string can be
electrical (thermo-couples etc.) or optical, and optical
configurations include e.g. distributed temperature sensing systems
based on Raman, Rayleigh or Brillouin effects, and/or single point
sensors based on FBG sensors, Fabry-Perot sensors or other means of
measuring temperature.
[0037] An embodiment for doing this is illustrated in FIG. 4, which
utilizes a technique used in DTS installations in Steam Assisted
Gravity Drainage wells used in the Canadian oil sands operations
where it is common to pump optical fibers into conduits for
temperature sensing. A conduit 430 (often 1/4'' metal tubes) is
shown deployed in a double ended configuration. The fluid flow goes
down hole in conduit 430 usually to the bottom of the well where a
Turn-Around-Sub (TAS) 450 is installed, and the fluid comes up the
other conduit 440. The optical fiber, which becomes the permanently
installed sensor, is deployed in the fluid flow and the distributed
forces acting on the fiber and drags into the conduit. The fiber
can either be deployed in a single ended fashion where the fiber
stops at TAS 450, or it can be pumped all the way to the surface in
a double-ended configuration. A second fiber can be pumped in on
top of the first fiber, although it is more challenging to get the
second fiber to full depth. The second fiber can be used as a
calibration string, either as a distributed system or with single
point sensors suitably attached to the cable. The calibration
string can also be a stiff cable with thermo-couples and/or optical
fibers for distributed and/or point temperature sensors. The stiff
cable can be pushed into the return conduit 440 in the case of a
single ended installation. This method uses a reference sensor in
the cable, and the calibration is done to the well bore
temperature. Different temperatures may occur during steam
injection and when the well is put on production, and the variation
over temperature can be used to achieve a solid calibration.
EXAMPLE 5
[0038] A Distributed Acoustic Sensing (DAS) system may have
different coupling between the fiber and the formation due to e.g.
cement around the sensing cable. The acoustic amplitude may vary,
and it may be advantageous to have a better understanding of where
you have good coupling to the formation and where there may be less
coupling and therefore lower signals.
[0039] This re-calibration can be done as follows. As shown in FIG.
5, a calibration string 520 can be deployed into the well bore
within casing 510 in close proximity to the permanently installed
DAS system 515. The DAS sensing cable 515 may be permanently
cemented in place between the casing 510 and the formation 550, and
normally run to the bottom of the well. Calibration string 520 can
be equipped with a calibrated noisemaker 530 and can be inserted in
the well and used to apply a characteristic acoustic signature on
one or several downhole points in close proximity to installed
sensor 515 and thereby log the acoustic signature of the DAS
system. A thermal point event can also be used for depth
calibration purposes when there is a DTS system present in the same
sensing cable as the DAS fiber.
EXAMPLE 6
[0040] Seismic sensors may be permanently installed in a well, and
cemented in place behind casing, or attached to tubing where
coupling to the well is done mechanically or magnetically. It is
however impossible to know how well the installed sensor is coupled
to the formation, and the seismic signal amplitude is directly
proportional to how well the installed sensor is coupled to the
formation. Seismic sensors may also have moving parts and the
orientation may be un-known.
[0041] This re-calibration can be done as follows. Referring to
FIG. 6 representing a formation 630 a permanently installed seismic
sensor 640 is attached to the outside of casing 610, possibly in a
cement 625 matrix, with communication back to the surface via
tubing 650. A calibration string 620 with a vibration source 670
can be inserted in the well and located in close proximity of the
permanently installed seismic sensor 640. The calibration string
may have mechanical coupling to the tubular structure where the
seismic sensors are located. Examples of mechanical coupling could
be a spring-loaded locking arm, a mechanical packer, or a
bow-spring type device that mechanically couples the calibration
string with the tubular structure where the seismic sensors are
located. As shown in FIG. 6 the mechanically coupling is
accomplished via locking arm 680, pressed against the casing or
tubing 610. The vibration of vibration source 670 will allow
calibration and health check of the fiber optic seismic sensors and
can also be used to verify sensor orientation assuming the
calibration string is properly equipped.
[0042] The calibration string may be designed to couple both shear
and pressure waves through a mechanical arm or other mechanical
coupling device or the calibration string may sit in a fluid
without mechanical coupling where pressure waves are mainly used
for calibration purposes.
EXAMPLE 7
[0043] An electromagnetic sensing system can be permanently
installed in a well.
[0044] A calibration string can be inserted in the well in close
proximity to the installed electromagnetic sensing system that
contains small permanent magnets or electrical coils that can be
used to generate a characteristic magnetic field signature. The
calibration string can then be used for calibration and health
check of the installed electromagnetic sensing system. FIG. 7
illustrates such a system. A well casing 710, possibly backed up by
a layer of cement 705 lies within the formation 700. A calibration
string 720 has been installed inside well casing 710 near a
permanently installed electromagnetic sensing system 740, which is
in communication with the surface via cable 715. The permanently
installed electromagnetic sensing system 740 may be in cement 705
behind the casing. The calibration string 720 has installed either
small permanent magnets or electrical coils 725. These are used to
generate a characteristic magnetic signature and electromagnetic
sensor 710 can be calibrated against that.
[0045] Although certain embodiments and their advantages have been
described herein in detail, it should be understood that various
changes, substitutions and alterations could be made without
departing from the coverage as defined by the appended claims.
Moreover, the potential applications of the disclosed techniques is
not intended to be limited to the particular embodiments of the
processes, machines, manufactures, means, methods and steps
described herein. As a person of ordinary skill in the art will
readily appreciate from this disclosure, other processes, machines,
manufactures, means, methods, or steps, presently existing or later
to be developed that perform substantially the same function or
achieve substantially the same result as the corresponding
embodiments described herein may be utilized. Accordingly, the
appended claims are intended to include within their scope such
processes, machines, manufactures, means, methods or steps.
* * * * *