U.S. patent application number 13/996439 was filed with the patent office on 2013-11-14 for system and method for monitoring strain & pressure.
The applicant listed for this patent is Michael Charles Minchau. Invention is credited to Michael Charles Minchau.
Application Number | 20130298665 13/996439 |
Document ID | / |
Family ID | 46314736 |
Filed Date | 2013-11-14 |
United States Patent
Application |
20130298665 |
Kind Code |
A1 |
Minchau; Michael Charles |
November 14, 2013 |
SYSTEM AND METHOD FOR MONITORING STRAIN & PRESSURE
Abstract
A method for monitoring a well treatment, comprising the steps
of installing at least one distributed acoustic strain sensor in at
least one monitoring well, said monitoring well being a known
distance from the treatment well, initiating a well treatment on
the first well, monitoring the formation surrounding the monitoring
well using the distributed acoustic strain sensor, and using the
distributed acoustic strain sensor, detecting a change in strain at
a first location in the monitoring well, using the change in strain
to make determinations about the well treatment. The sensor may
comprise a fiber optic cable. The change in strain may be used as
an indicator that the effect of the well treatment has extended
beyond a predetermined preferred treatment zone, the treatment may
be a fracture treatment, and the well treatment may be controlled
or ceased based on the determinations made in step e).
Inventors: |
Minchau; Michael Charles;
(Calgary, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Minchau; Michael Charles |
Calgary |
|
CA |
|
|
Family ID: |
46314736 |
Appl. No.: |
13/996439 |
Filed: |
December 9, 2011 |
PCT Filed: |
December 9, 2011 |
PCT NO: |
PCT/US11/64105 |
371 Date: |
June 20, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61425603 |
Dec 21, 2010 |
|
|
|
Current U.S.
Class: |
73/152.51 |
Current CPC
Class: |
E21B 47/107 20200501;
G01B 11/16 20130101; G01B 11/18 20130101; E21B 43/26 20130101; E21B
47/07 20200501; E21B 47/06 20130101 |
Class at
Publication: |
73/152.51 |
International
Class: |
E21B 47/06 20060101
E21B047/06 |
Claims
1. A method for detecting the effect of a well treatment performed
in a first well, comprising the steps of: a) installing at least
one distributed acoustic strain sensor in at least one monitoring
well, said monitoring well being a known distance from the first
well; b) initiating a well treatment on the first well; c)
monitoring the formation surrounding the monitoring well using the
distributed acoustic strain sensor; d) using the distributed
acoustic strain sensor, detecting a change in strain or pressure at
a first location in the monitoring well; and e) using the change in
strain detected in step d) to make determinations about the well
treatment in step b).
2. The method according to claim 1 wherein distributed acoustic
strain sensors are installed in at least two monitoring wells.
3. The method according to claim 1 wherein each monitoring well is
between 50 m and 5000 m from the first well.
4. The method according to claim 1 wherein the distributed acoustic
sensor comprises a fiber optic cable.
5. The method according to claim 1 wherein the change in strain
detected in step d) indicates that the effect of the well treatment
has extended to or beyond the limit of a predetermined preferred
treatment zone.
6. The method according to claim 1 wherein the well treatment is a
fracture treatment.
7. The method according to claim 1 further including the step of
controlling the well treatment based on the determinations made in
step e).
8. The method according to claim 1, further including the step of
ceasing the well treatment based on the determinations made in step
e).
9. The method according to claim 1 further including the step of
detecting, at one or more locations that are vertically spaced from
the first locations, further changes in strain that are related to
the change in strain detected in step d).
10. The method according to claim 8 further including the step of
using the change in strain detected in step d) to determine
information about the formation between the first well and the
monitoring well.
Description
RELATED APPLICATIONS
[0001] The present case claims priority to U.S. provisional
application Ser. No. 61/425,603, filed on 21 Dec. 2010, which is
incorporated herein by reference in its entirety.
TECHNICAL FIELD OF THE INVENTION
[0002] The present disclosure relates generally to a system and a
method for measuring strain and/or pressure in an underground
formation.
BACKGROUND OF THE INVENTION
[0003] In oilfield operations there is a often need to measure
changes in formation strain or pressure that occur as a result of
well interventions such as hydraulic fracturing and fluid
injection. These operations generally create high pressures in the
formation, often leading to breakdown (fracturing) of the rock
matrix, and will strain the formation in a volume surrounding the
intervention. Measurement of this formation strain can be
diagnostic of the effectiveness of the intervention and can lead to
modification of the intervention parameters that can give
significant economic benefit if the measurement technique is
inexpensive enough. Changes in strain can occur over time scales
ranging from fractions of a second to years and can occur at
locations that are far away from the well where the intervention
takes place ("treatment well"), often affecting rock volumes
intersected by neighboring wells. Similarly, detection of abnormal
pressure may indicate fluid paths or potential breakdown or
formation/concrete.
[0004] Various methods for applying transducers and/or sensors to a
cylindrical structure such as casing and using the sensors or
transducers to monitor deformation of the structure as the
structure is subjected to various forces are known. For example,
U.S. Pat. No. 7,245,791 discloses that temperature variations may
impart additional strain to an optical fiber and to a supporting
structure, such as a well tubular and/or casing, about which the
optical fiber is wrapped, and that these temperature variations
affect the index of refraction in the optical fiber, so that
temperature variations may be considered independently for
calibrating the strain measurements.
[0005] Notwithstanding the foregoing, there is currently no in-situ
method for measuring, in a volume around the treatment well and at
an acceptable cost and accuracy, formation strain during well
interventions. Surface and vertical seismic profile (VSP)
measurements can be used, but these are not accurate and require
calibration, as they yield formation velocity as the raw
measurement, which in turn needs to be converted into strain. In
principle, formation strainmeters could be deployed in a permanent
installation outside of casing but this can be prohibitively
expensive, especially if multiple wells and depth stations are
targeted. Furthermore, it is sometimes desirable to detect
formation strain and/or pressure in a treatment well, which is
difficult if not impossible using traditional pressure or strain
gauges.
SUMMARY OF THE INVENTION
[0006] The present disclosure provides a system and an in-situ
permanent method for measuring formation strain in a volume around
the treatment well and at an acceptable cost and accuracy.
[0007] In preferred embodiments, the invention includes
installation of DAS fibers in both a treatment well and in
neighboring wells. Laser light enters the fiber above the wellhead
and a backscattered signal is measured by optical components at the
surface. Known optical time-domain reflectometry (OTDR) methods and
preferably used to infer formation strain based on the
backscattered signal from a segment of the fiber adjacent to the
formation. All depths can be interrogated in the time scale of
fractions of a millisecond, providing a virtually instantaneous
strain measurement at all depths of interest. Strain/pressure
assessments can be performed on many wells at once, providing a
sampling of the volume strain or pressure over potentially a large
area. The measurements can be used to diagnose and correct a
geomechanical model or can be used to directly intervene in the
treatment with or without integration with other measurements.
[0008] In some embodiments, the invention includes a method for
detecting the effect of a well treatment such as a fracturing
treatment or fluid injection performed in a first well, comprising
the steps of: a) installing at least one distributed acoustic
strain sensor in at least one monitoring well that is located a
known distance from the first well, b) initiating a well treatment
on the first well, c) monitoring the formation surrounding the
monitoring well using the distributed acoustic strain sensor, d)
using the distributed acoustic strain sensor, detecting a change in
strain at a first location in the monitoring well, and e) using the
change in strain or pressure detected in step d) to make
determinations about the well treatment in step b). The invention
can also be used to determine the lateral, horizontal or vertical
(formation) extent of the fracture network or induced hydraulic
fracture.
[0009] The distributed acoustic strain sensors may be installed in
one or more monitoring wells, with each monitoring well between 50
m and 5000 m from the first or treatment well. Each distributed
acoustic sensor preferably comprises a fiber optic cable and
associated laser interrogator unit for sending and receiving
optical signals through the fiber.
[0010] The change in strain detected in step d) can be used as an
indication that the effect of the well treatment has extended to or
beyond the limit of a predetermined preferred treatment zone and
the well treatment may be controlled or ceased based on the
determinations made in step e). The present method can also be used
to determine information about the formation between the first well
and the monitoring well.
[0011] Other embodiments of the invention relate to time-lapse
measurement of either proximal and/or distal strain or pressure, in
a formation before, during, and after production operations.
According to the invention, strain measurements can be measured
over long periods of
time--seconds/minutes/days/weeks/months/years--giving them greater
scope than normal seismic data.
[0012] As used herein, "well treatment" refers to any fluid
injection or removal process that may be carried out on a well,
including fraccing, solvent injection, production, and the
like.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] For a more complete understanding of the preferred
embodiments, reference is made to the accompanying drawing, which
is a schematic illustration of a system in accordance with a first
embodiment of the invention.
DETAILED DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS
[0014] The present disclosure relates generally to a system and a
method for monitoring strain or pressure in one or more monitoring
wells and using the collected information to control processes in a
treatment well or to understand the effectiveness of those
treatments.
[0015] In one embodiment, distributed acoustic sensors comprising
fiber optic cables such as are known in the art are deployed in one
or more monitoring wells that are located at a distance from the
treatment well. The distance between the treatment well and any
given monitoring well may be in the range of from 50 m to 5000 m.
If more than one monitoring well is used, the wells can be arranged
on opposite sides of or evenly spaced about the treatment well, or
the monitoring wells can be located in locations determined by the
geology and/or topography surrounding the well. If more than one
monitoring well is used, it is possible to collect more data about
the subsurface and therefore to provide more useful
information.
[0016] By way of example only, referring initially to FIG. 1, a
treatment well 10 and a monitoring well 20 are preferably located
according to a predetermined plan. In some embodiments, the
treatment well will be one in which a fraccing or other injection
operation will be performed.
[0017] Treatment well 10 may contain one or more tubulars and may
be cased, as shown. In some cases, the well treatment will comprise
pumping fluid into the well at sufficiently high pressure to
fracture the adjacent formation, as illustrated by arrows 11,
resulting in fractures 13.
[0018] One or more fiber optic cables 12 designed to collect
distributed strain measurements are deployed in monitoring well(s)
20 and coupled to the formation by any suitable means. In the
embodiment shown, monitoring well 20 has been cemented with a fiber
optic sensor embedded in the cement. It will be understood that the
optic fiber can also be clamped or bonded to a downhole tubular, or
acoustically coupled by any other means. One or more light boxes 14
containing laser light sources and signal-receiving means are
optically coupled to the fiber at the surface. The cable may be
double-ended, i.e. may be folded back in the middle so that both
ends of the cable are at the source, or it may be single-ended,
with one end at the source and the other end at a point that is
remote from the source. The length of the cable can range from a
few meters to several kilometers, or even hundreds of kilometers.
In either case, measurements can be based solely on backscattered
light, if there is a light-receiving means only at the source end
of the cable, or a light receiving means can be provided at the
second end of the cable, so that the intensity of light at the
second end of the fiber optic cable can also be measured.
[0019] In some embodiments, the light source may be a long
coherence length phase-stable laser and is used to transmit direct
sequence spread spectrum encoded light down the fiber. Localized
strain or other disruptions cause small changes to the fiber, which
in turn produce changes in the backscattered light signal. The
returning light signal thus contains both information about strain
changes and location information indicating where along the fiber
they occurred. In some embodiments, the location along the fiber
can be determined using spread spectrum encoding, which uniquely
encodes the time of flight along the length of the fiber.
[0020] When it is desired to make measurements, the light source
transmits at least one light pulse into the end of the fiber optic
cable and a backscattered signal is received at the
signal-receiving means. Known optical time-domain reflectometry
(OTDR) methods are preferably used to infer formation strain based
on the backscattered signal from one or more segments of the fiber
adjacent to the formation of interest.
[0021] Using the present invention, formation strain or pressure
can be measured in the monitoring well(s) or treatment well(s) over
the duration of the treatment process and, if desired, for a period
of time thereafter, providing information about changes in the
formation strain or pressure over time. Of particular interest are
strain measurements indicating that the effect of the injection in
the treatment well has extended to or beyond the limit of a
predetermined preferred treatment zone. Thus, for example, strain
in the formation resulting from the injection of fluid is
preferably detected by fiber optic cable 12 for at least the
duration of the injection. In addition, acoustic events
attributable strain-induced fractures may also be detectable by
fiber optic cable 12.
[0022] Similarly, measurements in a pressurize zone can be used to
sense movement of a pressure front. Pressure in the formation will
cause a dilation in the matrix, i.e. an isotropic strain in all
directions. A fiber oriented in any direction will pick this up as
long as is passes through a region of changing pressure--the
"pressure front."
[0023] All depths can be interrogated in the time scale of
fractions of a millisecond, providing a virtually instantaneous
strain measurement at all depths of interest. Strain and pressure
assessments can be performed on many wells at once, providing a
sampling of the volume strain over potentially a large area. The
measurements can be used to diagnose and correct a geomechanical
model or can be used to directly intervene in the treatment with or
without integration with other measurements. Thus, the present
invention allows control of pressures to reduce out-of-zone effects
and also allows better understanding of production given the
measured connectivity.
[0024] In addition to the foregoing, it has been observed that
strain anomalies typically travel from the treatment well to
neighboring wells and that, shortly after the strain anomaly
reaches a neighboring well, it travels up and down that wellbore,
creating pressure connectivity over a significant vertical column
(as measured using pressure gauges in the field data). This is
undesirable for optimal production of the zones. The present
invention makes it possible to monitor the treatment using DAS
signals in the monitoring wells and to stop pumping when initial
inter-well connectivity is established.
[0025] The present methods have no inherent lower limit to the
frequency of investigation and are therefore limited only by the
stability of the hardware over long time scales. There are various
methods of backscatter measurement, including the use of Rayleigh
and Brillouin backscattering, and one method may be preferred over
others for this implementation of the present invention, especially
at low frequency.
[0026] The particular embodiments disclosed above are illustrative
only, as the present claimed subject matter may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
Furthermore, no limitations are intended to the details of
construction or design herein shown, other than as described in the
claims below. It is therefore evident that the particular
illustrative embodiments disclosed above may be altered or modified
and all such variations are considered within the scope and spirit
of the present claimed subject matter. By way of example only, one
of skill in the art will recognize that the number and location of
the monitoring well(s) with respect to the first well, the number
and configuration of cables and sensors, the sampling rate and
frequencies of light used, and the nature of the cable, coupling
devices, light sources, light signals, and photodetectors can all
be modified within the scope of the invention. By way of further
example, embodiments have been described in which a fiber is placed
in one or more wells that are spaced apart from the treatment well.
It will be understood that fibers could also be placed in the
treatment well itself. Moreover, it will be appreciated that such a
development effort might be complex and time-consuming, but would
nevertheless be a routine undertaking for those of ordinary skill
in the art having the benefit of the present disclosure.
[0027] The subject matter of the present disclosure is described
with specificity. However, the description itself is not intended
to limit the scope of the claimed subject matter. The claimed
subject matter, thus, might also be embodied in other ways to
include different steps or combinations of steps similar to the
ones described herein, in conjunction with other present or future
technologies. Moreover, although the term "step" may be used herein
to connote different methods employed, the term should not be
interpreted as implying any particular order among or between
various steps herein disclosed except when the order of individual
steps is explicitly described.
[0028] For illustrative purposes only, two examples of
implementation of the inventive concepts are set forth below.
Example 1
Hydraulic Fracturing
[0029] According to a first exemplary embodiment, distributed OTDR
sensing can be used to detect hydraulic fracturing according to the
following workflow: [0030] deploy one or more DAS fibers in one or
more wells in the vicinity of an intended hydraulic fracturing
operation; [0031] prior to hydraulic fracturing in the area, record
noise levels along the fiber as a control measurement; [0032] upon
initiation of pumping of fracture fluids, for any or all fracture
stages and fluid types, including mini-frac (or test frac), record
the strain field as measured by the DAS system, for all locations
in the well where the formation can be affected by the fracture
operation; [0033] simulate the strain field as a function of time
and space using a geomechanical simulation; [0034] from the results
of the simulation, make a prediction of the axial strain
measurements at the places where the DAS fibers have made the
measurements; [0035] compare the predictions and measurements and
adjust the geomechanical model parameters to minimize the
difference; [0036] use the new geomechanical model to make further
predictions that can be compared with DAS (or other) measurements;
[0037] use the new geomechanical model to optimize perforation
locations and pumping schedule (and any other relevant parameters)
such that the predictions of the updated model, with the new
perforation locations and pumping schedule, predict optimal
production over the life of the field; and [0038] keep the
geomechanical model evergreen by including data from either infill
hydraulic fracturing, recompletion fractures, long-term depletion
or other changes in formation strain due to production
operations.
[0039] The foregoing workflow can be generalized beyond hydraulic
fracture detection to include any earth motion that can be measured
with DAS, including but not limited to pressure or radial
strain.
Example 2
Depletion
[0040] According to a second exemplary embodiment, the inventive
methods are used to measure time-dependent strain in a depleting
field. More specifically, the inventive methods provide a way to
measure moderate resolution differential depletion in a reservoir.
The cost and availability of fiber optic sensors, allows
construction of an areal picture of depletion induced strain.
[0041] Thus, according to this embodiment, distributed OTDR sensing
can be used to detect and monitor field depletion according to the
following workflow: [0042] deploy one or more DAS fibers in one or
more wells in the vicinity of an intended hydraulic fracturing
operation; [0043] prior to field startup, record noise levels along
the fibers as a control measurement; [0044] upon initiation of
field depletion, the strain field as measured by the DAS system,
for all instrumented wells; [0045] simulate the strain field as a
function of time and space using a geomechanical simulation; [0046]
from the results of the simulation, make a prediction of the axial
strain measurements at the places where the DAS fibers have made
the measurements; [0047] compare the predictions and measurements
and adjust the geomechanical model parameters to minimize the
difference therebetween; [0048] make changes in the model as
required to match the data highlight differences in
subsidence/depletion for different parts of a formation, leading to
localized interventions; [0049] alternatively, depleted/depleting
areas may be obvious even without the benefit of a geomechanical
model as areas with greater or lesser strain changes; [0050] if the
fiber is also configured to measure formation pressure, a measure
of rock compressibility might be possible from strain and
pressure.
[0051] While the invention has the particular advantaged described
above, it can be used advantageously to detect inter-well effects
caused by other sources and can be used to determine information
about properties of the formation between wells. Accordingly, the
protection sought herein is as set forth in the claims below.
* * * * *