U.S. patent application number 15/036635 was filed with the patent office on 2016-09-29 for hydraulic fracture geometry monitoring with downhole distributed strain measurements.
The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to Karn Agarwal, Michael J. Mayerhofer, Norman R. Warpinski.
Application Number | 20160282507 15/036635 |
Document ID | / |
Family ID | 53543298 |
Filed Date | 2016-09-29 |
United States Patent
Application |
20160282507 |
Kind Code |
A1 |
Mayerhofer; Michael J. ; et
al. |
September 29, 2016 |
HYDRAULIC FRACTURE GEOMETRY MONITORING WITH DOWNHOLE DISTRIBUTED
STRAIN MEASUREMENTS
Abstract
A system for use with a subterranean well can include a
distributed strain sensor that senses strain along a casing which
lines a treatment wellbore. The distributed strain sensor can
extend across at least one fracture that intersects the wellbore. A
method of monitoring at least one fracture in a subterranean well
can include sensing strain in a portion of a casing where the
fracture intersects the casing, the sensing being performed with a
distributed strain sensor, and determining a geometry of the
fracture, based on the sensing. The geometry can include a width of
the fracture, a height of the fracture and an orientation of the
fracture relative to a wellbore. The distributed strain sensor can
include an optical waveguide.
Inventors: |
Mayerhofer; Michael J.;
(Houston, TX) ; Warpinski; Norman R.; (Cypress,
TX) ; Agarwal; Karn; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Family ID: |
53543298 |
Appl. No.: |
15/036635 |
Filed: |
July 8, 2014 |
PCT Filed: |
July 8, 2014 |
PCT NO: |
PCT/US2014/045659 |
371 Date: |
May 13, 2016 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
G01L 1/246 20130101;
G01V 8/10 20130101; E21B 49/006 20130101; G01V 8/02 20130101; G01L
1/242 20130101 |
International
Class: |
G01V 8/02 20060101
G01V008/02; E21B 49/00 20060101 E21B049/00 |
Foreign Application Data
Date |
Code |
Application Number |
Jan 20, 2014 |
US |
PCT/US2014/012178 |
Claims
1. A system for use with a subterranean well, the system
comprising: a distributed strain sensor that senses strain along a
casing which lines a treatment wellbore, wherein the distributed
strain sensor extends across at least one fracture that intersects
the wellbore.
2. The system of claim 1, wherein the distributed strain sensor
comprises an optical waveguide.
3. The system of claim 2, further comprising an optical
interrogator that detects optical scatter in the optical
waveguide.
4. The system of claim 1, wherein the distributed strain sensor is
positioned external to the casing.
5. The system of claim 1, wherein the fracture extends outwardly
from the casing into an earth formation penetrated by the
wellbore.
6. The system of claim 1, wherein the distributed strain sensor
extends across multiple perforated sections of the casing, and
wherein fracture initiation at each of the perforated sections is
indicated respectively by the strain in the casing sensed by the
distributed strain sensor at each of the perforated sections.
7. The system of claim 1, wherein closure of the fracture is
indicated by a reduction of the strain in the casing sensed by the
distributed strain sensor.
8. The system of claim 1, wherein a change in a geometry of the
fracture is correlated to a change in fluid flow between the
wellbore and an earth formation penetrated by the wellbore.
9. A method of monitoring at least one fracture in a subterranean
well, the method comprising: sensing strain in a portion of a
casing where the fracture intersects the casing, the sensing being
performed with a distributed strain sensor; and determining a
geometry of the fracture, based on the sensing.
10. The method of claim 9, wherein the geometry comprises a
selected one or more of the group consisting of a width of the
fracture, a height of the fracture and an orientation of the
fracture relative to a wellbore.
11. The method of claim 9, further comprising performing the strain
sensing and geometry determining over time, thereby detecting
changes in the geometry of the fracture over time.
12. The method of claim 9, wherein the distributed strain sensor is
positioned external to the casing.
13. The method of claim 9, wherein the distributed strain sensor
extends across the fracture.
14. The method of claim 9, wherein the distributed strain sensor
comprises an optical waveguide.
15. The method of claim 9, wherein an optical interrogator detects
optical scatter in the optical waveguide.
16. The method of claim 9, further comprising correlating a change
in the geometry of the fracture to a change in fluid flow between a
wellbore and an earth formation penetrated by the wellbore.
17. A system for use with a subterranean well, the system
comprising: a distributed strain sensor that senses strain along a
casing which lines a wellbore, the distributed strain sensor
comprising an optical waveguide, wherein the distributed strain
sensor extends across at least one fracture that intersects the
wellbore.
18. The system of claim 17, further comprising an optical
interrogator that detects optical scatter in the optical
waveguide.
19. The system of claim 17, wherein the fracture extends outwardly
from the casing into an earth formation penetrated by the
wellbore.
20. The system of claim 17, wherein closure of the fracture is
indicated by a reduction of the strain in the casing sensed by the
distributed strain sensor.
Description
TECHNICAL FIELD
[0001] This disclosure relates generally to equipment utilized and
operations performed in conjunction with subterranean wells and, in
one example described below, more particularly provides for
hydraulic fracture geometry monitoring using downhole distributed
strain measurements.
BACKGROUND
[0002] A hydraulic fracture is typically formed in an earth
formation by forcing fluid under pressure into the formation, with
the pressure being great enough to split or crack the formation. As
the fracture is being formed, proppant (such as, sand or man-made
particles) can be introduced into the fracture, so that the
fracture will be held open by the proppant after the pressure is
relieved.
[0003] Over time, as fluid is produced from the formation, pressure
in the fracture will typically decrease, and the fracture can
become narrower due to, for example, embedment of the proppant into
sides of the fracture, crushing of the proppant, etc. Such
narrowing of the fracture will decrease communicability of fluids
between the formation and a wellbore that penetrates the
formation.
[0004] It will, thus, be appreciated that improvements in the art
of monitoring fracture geometry are continually needed.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] FIG. 1 is a representative partially cross-sectional view of
a well system and associated method which can embody principles of
this disclosure.
[0006] FIG. 2 is an enlarged scale representative cross-sectional
view of a casing and fracture portion of the system.
[0007] FIG. 3 is a representative schematic view of a spatial
relationship between a treatment well and a fracture.
[0008] FIG. 4 is a representative graph of fracture induced axial
strain in a formation versus distance along the treatment well for
various different fracture pressures.
[0009] FIG. 5 is a representative schematic view of another example
of a spatial relationship between a treatment well and a
fracture.
[0010] FIG. 6 is a representative graph of fracture induced axial
strain in the formation versus distance along the treatment well
for various different fracture heights.
[0011] FIG. 7 is a representative schematic plan view of another
example of a spatial relationship between a treatment well and a
fracture.
[0012] FIG. 8 is a representative graph of fracture induced axial
strain in the formation versus distance along the treatment well
for various different fracture orientations.
[0013] FIG. 9 is a representative graph of axial strain in casing
and formation versus distance along the treatment well.
[0014] FIG. 10 is a representative cross-sectional view of a
fracture having a changed width.
[0015] FIG. 11 is a representative graph of production/injection
versus distance along the treatment well.
DETAILED DESCRIPTION
[0016] Representatively illustrated in FIG. 1 is a system 10 for
use with a subterranean well, and an associated method, which can
embody principles of this disclosure. However, it should be clearly
understood that the system 10 and method are merely one example of
an application of the principles of this disclosure in practice,
and a wide variety of other examples are possible. Therefore, the
scope of this disclosure is not limited at all to the details of
the system 10 and method described herein and/or depicted in the
drawings.
[0017] In the FIG. 1 example, a wellbore 12 penetrates an earth
formation 14. It is desired to fracture the formation 14 at various
zones 14a-e, in order to increase fluid communicability between the
wellbore 12 and each of the zones. The zones 14a-e could be
sections of the same formation 14, or they could be sections of
multiple formations.
[0018] As depicted in FIG. 1, the wellbore 12 is lined with casing
16 and cement 18. As used herein, the term "casing" is used to
indicate a protective wellbore lining. Casing can be any of the
tubulars known to those skilled in the art as tubing, casing or
liner. Casing can be made of metal (such as, steel) or non-metals
(such as, polymer or composite materials). Casing can be segmented
or continuous. Casing can be pre-formed or formed in situ. Thus,
the scope of this disclosure is not limited to use of any
particular type of casing.
[0019] As used herein, the term "cement" is used to indicate a
hardenable substance that seals off an annular space (such as,
between a casing and a wellbore, or between multiple tubulars) and
secures a casing or other tubular therein. Cement is not
necessarily cementitious, since epoxies, other polymers,
composites, etc., can be used instead of, or in combination with,
cementitious material. Thus, the scope of this disclosure is not
limited to use of any particular type of cement.
[0020] In the FIG. 1 example, the casing 16 and cement 18 have been
perforated in one or more clusters at the zone 14a, the zone 14a is
then fractured (e.g., by forcing fluids at high pressure into the
formation 14 via the perforations 28a), and then a plug 22 is set
in the casing to isolate the zone 14a. The casing 16 and cement 18
are then perforated at the zone 14b, the zone 14b is then fractured
(e.g., by forcing fluids at high pressure into the formation 14 via
the perforations 28b), and then another plug (not shown) is set in
the casing to isolate the zone 14b.
[0021] This process is repeated, until all of the zones 14a-e have
been fractured. Fractures 32 are formed in each of the zones
14a-e.
[0022] In other examples, the zones 14a-e may not be individually
perforated, fractured and then isolated by means of plugs set in
the casing 16. For example, sleeves and ports (not shown) may be
connected in the casing 16 at each of the zones 14a-e to provide
for selective communication with, and isolation from, the
individual zones. Thus, the scope of this disclosure is not limited
to use of any particular fracturing technique or sequence of
fracturing operations.
[0023] Also included in the system 10 is a distributed strain
sensor 30. In this example, the strain sensor 30 is connected on an
exterior of the casing 16.
[0024] The strain sensor 30 is "distributed," in that the strain
sensor can sense strain at a very large number of locations, or
substantially continuously, along its length. At present, typical
commercially available optical fiber distributed strain sensors
have a resolution of about one meter, so that, in a one thousand
meter section of interest in a wellbore, about one thousand strain
sensing locations are available.
[0025] Strains sensed by the distributed strain sensor 30 can be
available for evaluation in real time, so that decisions can be
made very quickly (such as, while a fracturing operation is being
performed) based on this strain information. As used herein, the
term "real time" means that an activity is performed immediately,
such as, within a few seconds or minutes, instead of hours or days
after an operation is concluded.
[0026] With the strain information available in real time, for
example, changes can be made to a fracturing operation while it
progresses, so that desired and/or optimum results can be achieved
from the fracturing operation. However, it should be understood
that it is not necessary for the strain information to be available
in real time in keeping with the scope of this disclosure.
[0027] In some examples, monitoring of strain can be performed for
extended periods (such as, for months or years), in order to
evaluate how fracture geometry changes over time (for example, as
the formation is drained and formation pressure decreases). In
those situations and others (for example, to perform a
post-fracturing evaluation in order to determine how operations
could be improved, provide fracture data to a customer, etc.), real
time output of strain information may not be a high priority.
[0028] In the FIG. 1 example, the distributed strain sensor 30
extends longitudinally across the perforated sections 28a,b of the
casing 16 so that, when fractures 32 are formed, the sensor will
extend across the fractures. This will enable the sensor 30 to be
used to detect how, when and where the fractures 32 form. For
example, the sensor 30 can be used to detect the fractures 32
formed in the zones 14a,b, and can also be used to detect that
fractures have not yet been formed in any of the zones 14c-e.
Oriented perforating (well-known to those skilled in the art) can
be used to avoid damage to the strain sensor 30 while
perforating.
[0029] Although the sensor 30 is representatively depicted as
extending longitudinally along the casing 16, parallel to a
longitudinal axis 34 of the casing, in other examples the sensor
could extend in other manners (e.g., helically or in a zig-zag
pattern) along the casing. In addition, although the sensor 30
extends across the perforated sections 28a-f of the casing, the
sensor preferably does not extend across any perforations
themselves, either when the perforations are formed, or when fluid
is injected or produced through the perforations.
[0030] Referring additionally to FIG. 2, an enlarged scale
cross-sectional view of a portion of the system 10 is
representatively illustrated. In this view, the manner in which a
fracture 32 intersects the wellbore 12 and extends through the
cement 18 to the casing 16 can be more clearly seen. No proppant is
depicted in FIG. 2 for clarity of illustration, but it will be
appreciated by those skilled in the art that proppant would
typically be placed in the fracture 32.
[0031] In this example, the distributed strain sensor 30 is
attached to an exterior of the casing 16 with straps or clamps 36.
A sufficient number of the clamps 36 can be used to ensure that the
sensor 30 experiences any strain in the casing 16 with a desired
resolution.
[0032] The sensor 30 of FIG. 2 includes an optical waveguide 38
housed within a protective outer tube 40. A filler 42 fills an
annular space between the optical waveguide 38 and the tube 40, and
the filler ensures that the optical waveguide experiences the same
strain as experienced by the tube.
[0033] For example, the filler 42 could comprise an epoxy or other
high strength hardenable polymer adhesive. In other examples, the
filler 42 could be a material that hardens relatively slowly, so
that it is flexible when deployed, but is set when fracturing
operations are performed. Thus, the scope of this disclosure is not
limited to use of any particular filler material.
[0034] The optical waveguide 38 can be a single mode, multi-mode,
polarization maintaining or other type of optical waveguide. The
optical waveguide 38 may comprise fiber Bragg gratings (FBG's),
intrinsic or extrinsic Fabry-Perot interferometers, or any
alteration of, or perturbation to, its refractive index along its
length. The optical waveguide 38 may be in the form of an optical
fiber, an optical ribbon or other waveguide form. Thus, the scope
of this disclosure is not limited to use of any particular type of
optical waveguide.
[0035] The optical waveguide 38 is optically connected to an
optical interrogator 44, for example, at or near the earth's
surface. The optical interrogator 44 is depicted schematically in
FIG. 1 as including an optical source 46 (such as, a laser or a
light emitting diode) and an optical detector 48 (such as, an
opto-electric converter or photodiode).
[0036] The optical source 46 launches light (electromagnetic
energy) into the waveguide 38, and light returned to the
interrogator 44 is detected by the detector 48. Note that it is not
necessary for the light to be launched into a same end of the
optical waveguide 38 as an end via which light is returned to the
interrogator 44.
[0037] Other or different equipment (such as, an interferometer or
an optical time domain or frequency domain reflectometer) may be
included in the interrogator 44 in some examples. The scope of this
disclosure is not limited to use of any particular type or
construction of optical interrogator.
[0038] A computer 50 is used to control operation of the
interrogator 44, and to record optical measurements made by the
interrogator. In this example, the computer 50 includes at least a
processor 52 and memory 54. The processor 52 operates the optical
source 46, receives measurement data from the detector 48 and
manipulates that data. The memory 54 stores instructions for
operation of the processor 52, and stores processed measurement
data. The processor 52 and memory 54 can perform additional or
different functions in keeping with the scope of this
disclosure.
[0039] In other examples, different types of computers may be used,
and the computer 50 could include other equipment (such as, input
and output devices, etc.). The computer 50 could be integrated with
the interrogator 44 into a single instrument. Thus, the scope of
this disclosure is not limited to use of any particular type or
construction of computer.
[0040] The optical waveguide 38, interrogator 44 and computer 50
may comprise a distributed strain sensing (DSS) system capable of
detecting strain as distributed along the optical waveguide. For
example, the interrogator 44 could be used to measure Brillouin or
coherent Rayleigh scattering in the optical waveguide 38 as an
indication of strain energy as distributed along the waveguide.
[0041] In addition, a ratio of Stokes and anti-Stokes components of
Raman scattering in the optical waveguide 38 could be monitored as
an indication of temperature as distributed along the waveguide in
a distributed temperature sensing (DTS) system. In other examples,
Brillouin scattering may be detected as an indication of
temperature as distributed along the optical waveguide 38.
[0042] In further examples, fiber Bragg gratings (not shown) could
be closely spaced apart along the optical waveguide 38 (at least in
locations where the fractures 32 are formed), so that strain in the
waveguide will result in changes in light reflected back to the
interrogator 44. An interferometer (not shown) may be used to
detect such changes in the reflected light.
[0043] It will be appreciated from a careful consideration of FIG.
2 that, as the fracture 32 widens, tensile strain in the casing 16
will result at a location where the fracture meets the casing. As
the fracture 32 widens, the tensile strain will increase. At
locations spaced apart from the fracture 32, compressive strain
will be experienced in the casing 16 due to the widening fracture.
Similarly, as the fracture 32 closes, the tensile strain in the
casing 16 at the location where the fracture meets the casing will
decrease, and the compressive strain at locations spaced apart from
the fracture will also decrease.
[0044] Referring additionally now to FIGS. 3 & 4, theoretical
strain in formation rock surrounding a treatment well is provided
at various pressures in the fracture 32. FIG. 3 depicts the
fracture 32 dimensions and orientation relative to the treatment
well longitudinal axis 34, and FIG. 4 is a graph of axial
(longitudinal) strain versus distance along the treatment wellbore
12.
[0045] In FIG. 3, the example fracture 32 is oriented orthogonal to
the wellbore axis 34. The fracture 32 has a height h.sub.f of 300
feet (.about.91.4 meters). S.sub.v is vertical (overburden) stress
in the formation 14, S.sub.hmax is maximum horizontal stress, and
S.sub.hmin is minimum horizontal stress. The wellbore axis 34 in
this example is aligned with a direction of the minimum horizontal
stress, thereby influencing the fracture 32 to form orthogonal to
the wellbore axis.
[0046] In FIG. 4, axial strain (longitudinal relative to the
wellbore 12) is plotted versus distance along the wellbore relative
to the location where the fracture 32 intersects the wellbore, for
various net pressures (P). As indicated by FIG. 4, as pressure in
the fracture 32 increases, compressive strain in the rock also
increases.
[0047] Interestingly, the compressive strain increases as a
distance from the fracture 32 increases, until a point of extremum
56 is reached, beyond which the compressive strain decreases
asymptotically. These points of extremum 56 are related to the
height h.sub.f of the fracture 32. Thus, by sensing the strain, the
height h.sub.f of the fracture can be empirically determined.
[0048] A magnitude of the strain at a given pressure is related to
a width of the fracture 32. Thus, by sensing the strain at a known
pressure in the fracture 32, a width of the fracture can be
determined. By sensing changes in the sensed strain over time at
known pressures, changes in the fracture 32 width can be
monitored.
[0049] Referring additionally now to FIGS. 5 & 6, theoretical
strain in formation rock surrounding a treatment well is provided
at given net pressure (P.sub.net) of 1000 pounds per square inch
(.about.6895 kpa) in the fracture 32 for different fracture heights
h.sub.f. FIG. 5 depicts the fracture 32 dimensions and orientation
relative to the treatment well longitudinal axis 34, and FIG. 6 is
a graph of axial (longitudinal) strain versus distance along the
treatment wellbore 12.
[0050] In FIG. 5, L.sub.f is the half-length of the fracture 32. In
this example, the half-length L.sub.f is 400 ft (.about.122
meters). FIG. 6 demonstrates how a distance between the points of
extremum 56 at a given pressure in the fracture 32 is related to
the height h.sub.f of the fracture.
[0051] Referring additionally now to FIGS. 7 & 8, theoretical
strain in formation rock surrounding a treatment well is provided
at various angular orientations of the fracture 32 relative to the
wellbore axis 34. FIG. 7 depicts the angular orientation of the
fracture 32 relative to the treatment well longitudinal axis 34 in
plan view, and FIG. 8 is a graph of axial (longitudinal) strain
versus distance along the treatment wellbore 12.
[0052] In FIG. 7, .theta. is the angular orientation of the
fracture 32 relative to the wellbore axis 34. In FIG. 8, the manner
in which the strain in the formation rock changes, depending on the
angular orientation of the fracture 32 can be clearly seen.
[0053] The strain curves depicted in FIG. 8 were computed for a
fracture pressure (P.sub.net) of 1000 psi (.about.6895 kpa),
fracture half-length L.sub.f of 400 ft (.about.122 meters) and
fracture height h.sub.f of 300 ft (.about.91.4 meters). Note how a
shape of the strain curves change as the fracture 32 orientation
changes. Thus, it will be appreciated that an orientation of the
fracture 32 relative to the wellbore axis 34 can be empirically
determined, based on comparing the sensed strain versus distance
along the wellbore axis to the modeled strain for an assumed
fracture geometry.
[0054] Referring additionally now to FIG. 9, axial strain in the
formation rock and axial strain in the casing 16 is plotted versus
distance along the wellbore axis 34. Note that these strain curves
overlap over most of their extents. This is because the formation
14 is substantially coupled to the casing 16 over most of its
length by the cement 18 (see FIG. 1).
[0055] However, where the fracture 32 splits the cement 18 (see
FIG. 2), there is no direct coupling between the formation 14 and
the casing 16. At this area, the casing 16 will experience tensile
strain. This tensile strain can be detected using the distributed
strain sensor 30, because the sensor extends across the fracture 32
and is coupled to the casing 16 (see FIG. 2).
[0056] Thus, the distributed strain sensor 30 can be used to detect
not only a presence of the fracture 32, but also various geometric
values of the fracture (e.g., width, height and orientation
relative to the wellbore 12). Changes in the fracture 32 (such as,
changes in the fracture width) over time can be determined by
monitoring changes in the strain over time.
[0057] Strain events occurring during production from a well can
also be related to changes in a production profile (production as
distributed along a wellbore) obtained from distributed temperature
sensing (DTS) and distributed acoustic sensing (DAS) monitoring
systems (production monitoring with DTS and DAS systems is well
known to those skilled in the art). In this manner, it can be
ascertained whether mechanical deterioration of fractures (e.g.,
resulting in decreased fracture width) causes changes in production
behavior.
[0058] Referring additionally now to FIG. 10, the fracture 32 is
representatively illustrated, the fracture having experienced a
change in width (w.sub.f). As with FIG. 2, no proppant is depicted
in the fracture 32 for clarity of illustration.
[0059] A previous width of the fracture 32 is shown in FIG. 10 in
dashed lines. The fracture width w.sub.f could change for any of a
variety of reasons, or a combination of reasons. For example,
proppant in the fracture 32 may have been crushed, the proppant
could have displaced from the fracture (such as, back into the
casing 16), the proppant could have become embedded into sides of
the fracture, etc. Thus, the scope of this disclosure is not
limited to any particular reason for the fracture width w.sub.f to
change.
[0060] It will be appreciated that, if the fracture width w.sub.f
decreases, communicability between the formation 14 and the
interior of the casing 16 via the fracture will also be decreased.
As a result, production or injection of fluids via the fracture 32
can be expected to decrease accordingly.
[0061] Referring additionally now to FIG. 11, a graph of
production/injection versus distance along the wellbore 12 is
representatively illustrated. The vertical production/injection
axis can represent any suitable indicator of production or
injection, such as, mass or volumetric flow rate, flow velocity,
etc. The horizontal distance axis is centered approximately at the
perforations 28a as depicted in FIG. 10.
[0062] In solid lines in FIG. 11, it can be seen that
production/injection increases at the perforations 28a, compared to
either side of the perforations along the wellbore 12. This is to
be expected, in this example, since there is no communicability
with the formation 14, except at the perforations 28a.
[0063] In dashed lines in FIG. 11, it can be seen that
production/injection was previously greater. A reduction in the
production/injection is experienced, due to the decrease in
fracture width w.sub.f depicted in FIG. 10.
[0064] Thus, it will be understood that changes in the fracture
geometry can be correlated to changes in production/injection. For
example, if the strain sensor 30 detects a change in strain
indicating that the fracture width w.sub.f has decreased, and
concurrently a decrease in production/injection at the fracture 32
is detected, it can be deduced that the change in
production/injection is due to the change in fracture width.
[0065] Note that measurements of production/injection can be
obtained by any of a variety of different means. For example,
distributed temperature sensing systems, distributed acoustic
sensing systems, conventional production logging tools, downhole
flowmeters and other equipment and techniques can be used to
measure production or injection. Therefore, the scope of this
disclosure is not limited to any particular production/injection
measurement method or technique.
[0066] It may now be fully appreciated that the above disclosure
provides significant advances to the art of monitoring fracture
geometry. In examples described above, values of various geometric
dimensions of the fracture 32 can be determined by measuring strain
along the casing 16 with the distributed strain sensor 30.
[0067] A system 10 for use with a subterranean well is provided to
the art by the above disclosure. In one example, the system 10
comprises a distributed strain sensor 30 that senses strain along a
casing 16 which lines a wellbore 12. The distributed strain sensor
30 extends across at least one fracture 32 that intersects the
wellbore 12.
[0068] The distributed strain sensor 30 may comprise an optical
waveguide 38. The system 10 can include an optical interrogator 44
that detects optical scatter in the optical waveguide 38. In other
examples, other types of distributed strain sensors may be
used.
[0069] The distributed strain sensor 30 may be positioned external
to the casing 16.
[0070] The fracture 32 may extend outwardly from the casing 16 into
an earth formation 14 penetrated by the wellbore 12.
[0071] The distributed strain sensor 30 may extend across multiple
perforated sections 28a-f of the casing 16. Fracture initiation at
each of the perforated sections 28a-f can be indicated respectively
by tensile strain in the casing 16 sensed by the distributed strain
sensor 30 at each of the perforated sections 28a-f.
[0072] Closure of the fracture 32 can be indicated by a reduction
of tensile strain in the casing 16 sensed by the distributed strain
sensor 30. A change in a width w.sub.f of the fracture 32 can be
correlated to a change in fluid flow (production/injection) between
the wellbore 12 and an earth formation 14 penetrated by the
wellbore 12.
[0073] A method of monitoring at least one fracture 32 in a
subterranean well is also provided to the art by the above
disclosure. In one example, the method comprises sensing strain in
a portion of a casing 16 where the fracture 32 intersects the
casing 16, the sensing being performed with a distributed strain
sensor 30; and determining a geometry of the fracture 32, based on
the sensing.
[0074] The geometry can comprise a selected one or more of: width
of the fracture 32, height of the fracture and orientation of the
fracture relative to a wellbore 12.
[0075] The method can also include performing the strain sensing
step and geometry determining step over time, thereby detecting
changes in the geometry of the fracture 32 over time. The method
can include correlating a change in the geometry (e.g., the width
w.sub.f) of the fracture 32 to a change in fluid flow between a
wellbore 12 and an earth formation 14 penetrated by the
wellbore.
[0076] Although various examples have been described above, with
each example having certain features, it should be understood that
it is not necessary for a particular feature of one example to be
used exclusively with that example. Instead, any of the features
described above and/or depicted in the drawings can be combined
with any of the examples, in addition to or in substitution for any
of the other features of those examples. One example's features are
not mutually exclusive to another example's features. Instead, the
scope of this disclosure encompasses any combination of any of the
features.
[0077] Although each example described above includes a certain
combination of features, it should be understood that it is not
necessary for all features of an example to be used. Instead, any
of the features described above can be used, without any other
particular feature or features also being used.
[0078] It should be understood that the various embodiments
described herein may be utilized in various orientations, such as
inclined, inverted, horizontal, vertical, etc., and in various
configurations, without departing from the principles of this
disclosure. The embodiments are described merely as examples of
useful applications of the principles of the disclosure, which is
not limited to any specific details of these embodiments.
[0079] The terms "including," "includes," "comprising,"
"comprises," and similar terms are used in a non-limiting sense in
this specification. For example, if a system, method, apparatus,
device, etc., is described as "including" a certain feature or
element, the system, method, apparatus, device, etc., can include
that feature or element, and can also include other features or
elements. Similarly, the term "comprises" is considered to mean
"comprises, but is not limited to."
[0080] Of course, a person skilled in the art would, upon a careful
consideration of the above description of representative
embodiments of the disclosure, readily appreciate that many
modifications, additions, substitutions, deletions, and other
changes may be made to the specific embodiments, and such changes
are contemplated by the principles of this disclosure. For example,
structures disclosed as being separately formed can, in other
examples, be integrally formed and vice versa. Accordingly, the
foregoing detailed description is to be clearly understood as being
given by way of illustration and example only, the spirit and scope
of the invention being limited solely by the appended claims and
their equivalents.
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