U.S. patent application number 14/495487 was filed with the patent office on 2015-03-26 for method of conducting diagnostics on a subterranean formation.
The applicant listed for this patent is Shell Oil Company. Invention is credited to Anastasia DOBROSKOK, Ernesto Rafael FONSECA OCAMPOS, Alexei Alexandrovich SAVITSKI.
Application Number | 20150083405 14/495487 |
Document ID | / |
Family ID | 52689938 |
Filed Date | 2015-03-26 |
United States Patent
Application |
20150083405 |
Kind Code |
A1 |
DOBROSKOK; Anastasia ; et
al. |
March 26, 2015 |
METHOD OF CONDUCTING DIAGNOSTICS ON A SUBTERRANEAN FORMATION
Abstract
A method including providing sensors in injection and
observation wells; increasing pressure within the injection well
until a fracture extends from an initiation location through a
portion of a subterranean formation to an intersection location in
the observation well, wherein increasing pressure within the
injection well comprises introducing fluid into the injection well;
obtaining a measurement indicative of fracture initiation from the
first sensor; determining a height of the fracture at the injection
well; obtaining a measurement indicative of fracture intersection
from the second sensor; determining a volume of fluid introduced
between the fracture initiation and the fracture intersection;
determining a distance between the initiation location and the
intersection location; determining a time lapse between the
fracture initiation and the fracture intersection; and using the
determined values, calculating a hydraulic fracturing
characteristic.
Inventors: |
DOBROSKOK; Anastasia;
(Houston, TX) ; FONSECA OCAMPOS; Ernesto Rafael;
(Houston, TX) ; SAVITSKI; Alexei Alexandrovich;
(Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Shell Oil Company |
Houston |
TX |
US |
|
|
Family ID: |
52689938 |
Appl. No.: |
14/495487 |
Filed: |
September 24, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61882139 |
Sep 25, 2013 |
|
|
|
Current U.S.
Class: |
166/250.1 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 47/002 20200501; E21B 47/06 20130101 |
Class at
Publication: |
166/250.1 |
International
Class: |
E21B 43/26 20060101
E21B043/26; E21B 47/00 20060101 E21B047/00; E21B 47/06 20060101
E21B047/06 |
Claims
1. A method comprising: a. providing a first sensor in an injection
well penetrating a subterranean formation; b. providing a second
sensor in an observation well penetrating the subterranean
formation; c. increasing pressure within the injection well until a
fracture extends from an initiation location in the injection well
through a portion of the subterranean formation to an intersection
location in the observation well, wherein increasing pressure
within the injection well comprises introducing fluid into the
injection well; d. obtaining a measurement indicative of fracture
initiation from the first sensor; e. determining a height of the
fracture at the injection well; f. obtaining a measurement
indicative of fracture intersection from the second sensor; g.
determining a volume of fluid introduced between the fracture
initiation and the fracture intersection; h. determining a distance
between the initiation location and the intersection location; i.
determining a time lapse between the fracture initiation and the
fracture intersection; and j. using the determined values,
calculating a hydraulic fracturing characteristic.
2. The method of claim 1, wherein the first sensor comprises a
distributed temperature sensor.
3. The method of claim 1, wherein the second sensor comprises a
distributed acoustic sensor.
4. The method of claim 1, wherein step (a) comprises placing the
first sensor in a substantially vertical portion of the injection
well; wherein initiation location is in the substantially vertical
portion of the injection well.
5. The method of claim 1, wherein step (b) comprises placing the
second sensor in a deviated portion of the observation well;
wherein the intersection location is in the deviated portion of the
observation well.
6. The method of claim 1, wherein the measurement of step (d)
comprises a temperature measurement, the method further comprising:
obtaining at least one baseline temperature measurement from the
first sensor prior to obtaining the temperature measurement of step
(d); and comparing the baseline temperature measurement with the
temperature measurement of step (d) to determine a time of
initiation.
7. The method of claim 1, wherein the measurement of step (d)
comprises a pressure measurement, the method further comprising:
obtaining at least one baseline pressure measurement from the first
sensor prior to obtaining the pressure measurement of step (d); and
comparing the baseline pressure measurement with the pressure
measurement of step (d) to determine a time of initiation.
8. The method of claim 1, wherein the measurement of step (f)
comprises an acoustic measurement, the method further comprising:
obtaining at least one baseline acoustic measurement from the
second sensor prior to obtaining the acoustic measurement of step
(f); and comparing the baseline acoustic measurement with the
acoustic measurement of step (f) to determine a time of
intersection.
9. The method of claim 1, further comprising, obtaining a location
measurement from the first sensor and obtaining a location
measurement from the second sensor, wherein determining the
distance of step (h) comprises comparing the location
measurements.
10. The method of claim 1, wherein determining the height of the
fracture comprises obtaining at least one additional measurement
from the first sensor.
11. The method of claim 10, wherein the measurement of step (d)
comprises a temperature measurement, wherein the additional
measurement from the first sensor comprises a temperature
measurement, and wherein determining the height of the fracture
comprises comparing the temperature measurements.
12. The method of claim 1, further comprising determining a Young's
modulus and Poisson ratio of the portion of the subterranean
formation through which the fracture extends, complete elliptical
integral of the second kind, and fracture net pressure; wherein the
calculating of step (i) further comprises using the determined
Young's modulus, Poisson ratio, complete elliptical integral of the
second kind, and fracture net pressure.
13. The method of claim 1, wherein the hydraulic fracturing
characteristic comprises a leak-off volume.
14. The method of claim 1, wherein the hydraulic fracturing
characteristic comprises a leak-off coefficient.
15. The method of claim 1, wherein the hydraulic fracturing
characteristic comprises permeability, the method further
comprising determining fluid pressure in the fracture, reservoir
pressure, viscosity of the fluid, and fluid compressibility,
wherein the calculating of step (i) further comprises using the
determined fluid pressure in the fracture, reservoir pressure,
viscosity of the fluid, and fluid compressibility.
Description
RELATED CASES
[0001] This application claims the benefit of U.S. Provisional
Application No. 61/882,139, filed on Sep. 25, 2013, which is
incorporated herein by reference.
FIELD OF THE INVENTION
[0002] The invention relates to a method of conducting diagnostics
on a subterranean formation.
BACKGROUND
[0003] Hydraulic fracturing of reservoirs is a technology
optimizing the value of subterranean hydrocarbon-bearing formations
and, in particular, of unconventional gas and liquid rich shale
deposits. Due to the tight nature of formations containing such
deposits, standard techniques for reservoir characterization and
hydraulic fracture design are often inapplicable or present
interpretation challenges. Understanding leak-off process is a key
component of characterization and design. A standard practice of
leak-off estimation involves conducting a minifrac or leak-off
test. Due to very low permeability of the unconventional gas and
liquid rich shale formations this test generally provides poor
results. Another way to estimate the leak-off is to use analytical
approach which requires knowledge of some parameters of the
formation such as permeability and porosity. However, these
parameters can be very hard to estimate in tight formations.
SUMMARY OF THE INVENTION
[0004] In accordance with one aspect of the present disclosure, a
method includes providing a first sensor in an injection well
penetrating a subterranean formation. The method also includes
providing a second sensor in an observation well penetrating the
subterranean formation. The method further includes increasing
pressure within the injection well until a fracture extends from an
initiation location in the injection well through a portion of the
subterranean formation to an intersection location in the
observation well, wherein increasing pressure within the injection
well comprises introducing fluid into the injection well. The
method includes obtaining a measurement indicative of fracture
initiation from the first sensor. Additionally, the method includes
determining a height of the fracture at the injection well. The
method also includes obtaining a measurement indicative of fracture
intersection from the second sensor. The method includes
determining a volume of fluid introduced between the fracture
initiation and the fracture intersection. Additionally, the method
includes determining a distance between the initiation location and
the intersection location. The method also includes determining a
time lapse between the fracture initiation and the fracture
intersection. Additionally, the method includes using the
determined values, calculating a hydraulic fracturing
characteristic.
BRIEF DESCRIPTION OF THE FIGURES
[0005] FIG. 1 illustrates a schematic of an injection well and an
observation well with a fracture extending therebetween in
accordance with one aspect of the present disclosure.
DETAILED DESCRIPTION
[0006] The present disclosure provides methods for field testing
and deriving hydraulic fracturing parameters. Generally, a
combination of distributed temperature and acoustic sensors are
installed in a vertical and deviated well respectively to measure
fracture height, time required for the fracture to grow to a
length, and fluid leak-off rate. The estimated parameters may also
be employed in history matching to decrease the uncertainty in
characterizing the stress field, fracture toughness of the
formation, and other related properties.
[0007] Referring now to FIG. 1, an injection well 10 and an
observation well 12 may be provided. The injection well 10 may be a
hydraulically fractured well. One or both of the injection well 10
and the observation well 12 may penetrate a subterranean formation
14 of interest. For example, the subterranean formation 14 may
contain hydrocarbon or other natural resources. The injection well
10 and the observation well 12 may originate at a surface 15 at a
single pad (not shown). However, as illustrated, the injection well
10 originates at the surface 15 at an injection pad 16 and the
observation well 12 originates at the surface 15 at an observation
pad 18. A method of evaluating a formation may include placing or
otherwise providing a sensor 20 in the injection well 10 at a
location where the sensor 20 can sense a parameter indicative of
fracture initiation from an initiation location 24 in the injection
well 10. As illustrated, the initiation location 24 is a
perforation in casing, isolated by two packers 23. The sensor 20
may be a distributed temperature sensor (DTS), a pressure gauge,
multiple pressure gauges, etc. For example a fiber optic DTS may be
attached to the wellbore casing and provide measurements of
temperature decrease (or increase) in response to the injection of
cool (hot) fluid. In some embodiments, including the embodiment
illustrated, the sensor 20 may be placed in a substantially
vertical portion 25 of the injection well 10. In such embodiments,
the initiation location 24 may be in the substantially vertical
portion 25 of the injection well 10.
[0008] The method may also include placing or otherwise providing
another sensor 26 in the observation well 12 at a location where
the sensor 26 can sense a parameter indicative of fracture
intersection at an intersection location 30 in the observation well
12. The sensor 26 may be a distributed acoustic sensor (DAS), a
DTS, a DAS/DTS combination, or any other instrumentation in the
observation well 12. A fiber optic DAS may be attached to the
wellbore casing and measure the deformation induced by fracturing.
A DAS and DTS may be simultaneously used in one wellbore.
Alternatively, pressure gauges may be present in the observation
well or in both injection and observation wells. In some
embodiments, including the embodiment illustrated, the sensor 26
may be placed in a deviated portion 31 of the observation well 12.
In such embodiments, the intersection location 30 may be in the
deviated portion 31 of the observation well 12.
[0009] The injection well 10 and the deviated portion 31 of the
observation well 12 may be positioned along the direction of
maximum horizontal stress .sigma..sub.H. Once the sensor 20 has
been provided in the injection well 10 and the sensor 26 has been
provided in the observation well 12, fluid may be introduced into
the injection well 10 at the surface 15. The pressure within the
injection well may be gradually increased by pressurizing the fluid
until a fracture 34 begins to form. The fracture 34 may extend from
the initiation location 24 in the injection well 10, through a
portion of the subterranean formation 14, to the intersection
location 30 in the observation well 12. While it is likely that the
fracture 34 would continue beyond the intersection location 30, the
present disclosure notes that the intersection location 30 is of
particular interest.
[0010] The initiation of the fracture 34 may provide a signal that
can be detected by the sensor 20. For example, breaking of the
subterranean formation 14 may be registered by a pressure change, a
thermal change, or some other change measurable by the sensor 20.
Thus, it may be possible to obtain a measurement indicative of
fracture initiation from the sensor 20. Such measurement may
include an indication of the sensed value (e.g., a temperature
measurement, a pressure measurement, deformation measurement, etc.)
and indication of a time ("initiation time" or t.sub.0=0) at which
the value was sensed. Such measurement(s) may be saved for later
reference and use. In order to sense a change in the measurement of
the sensor 20, a baseline measurement may be obtained from the
sensor 20 prior to any measurement associated with formation of the
fracture 34. Thus, determination of the time of initiation may
involve comparing the baseline measurement with one or more
subsequent measurements until a sufficient change characteristic of
fracture initiation is detected. Thus, determining the time at
which that change is detected provides a determination of the time
of initiation. That change may reach a threshold temperature,
pressure, or other value, depending on whether the sensor 20 is
configured to detect a temperature change (when the baseline and
subsequent measurements are temperature measurements), a pressure
change (when the baseline and subsequent measurements are pressure
measurements), or some other type of change The interpreted
fracture initiation time can be further compared with and supported
by the fracture initiation interpreted from the treating pressure
record.
[0011] The height 36 of the fracture 34 may be determined at the
injection well 10. Specifically, the height 36 of the fracture 34
may be determined at the initiation location 24 via radioactive
tracers, temperature logs, or any other instrumentation in the
injection well 10. In some embodiments, determining the height 36
of the fracture 34 may include obtaining an additional measurement
from the sensor 20. For example, if the sensor 20 is configured to
provide temperature measurements, changes in temperature along the
length of the sensor 20 may provide information about the height of
the fracture 34. Thus, determining the height 36 of the fracture
may involve comparison of temperature measurements of the sensor 20
over time.
[0012] As injection proceeds with closely monitored and recorded
injection volumes, the fracture 34 propagates through the
subterranean formation 14, until the fracture 34 intersects the
observation well 12 at the intersection location 30. The
intersection of the fracture 34 with the observation well 12 may
provide a signal that can be detected by the sensor 24. For
example, arrival of the fracture 34 at the observation well 12 may
be registered by an acoustic change or some other change measurable
by the sensor 26. Such measurement may include an indication of the
sensed value (e.g., an acoustic measurement, a temperature
measurement, or a combination thereof) and an indication of a time
("intersection time" or t) at which the value was sensed. Such
measurement(s) may be saved for later reference and use. In order
to sense a change in the measurement of the sensor 26, a baseline
measurement may be obtained from the sensor 26 prior to any
measurement associated with intersection of the fracture 34 with
the observation well 12. Thus, determination of the time of
intersection may involve comparing the baseline measurement with
one or more subsequent measurements until a sufficient change is
detected. Thus, determining the time at which that change is
detected provides a determination of the time of intersection. That
change may reach a threshold acoustic or other value, depending on
whether the sensor 26 is configured to detect an acoustic change
(when the baseline and subsequent measurements are acoustic
measurements or some other type of change).
[0013] The same process may optionally be repeated for additional
observation wells (not shown) with use of additional sensors (not
shown). In such instance, such additional measurement(s) may also
be saved for later reference and use in a similar manner as that
described with respect to the illustrated observation well 12.
[0014] The initiation time and the intersection time may be used to
determine a volume of fluid introduced between the fracture
initiation and the fracture intersection. For example, the
initiation time may be subtracted from the intersection time and a
volumetric flow rate may be multiplied by the time lapsed.
Alternatively, the initiation time might be set to zero, with a
timer starting to measure time at the initiation time and stop
measuring at the intersection time. Again, the time lapse may be
multiplied by a steady volumetric flow rate. Alternatively, the
volume of fluid introduced between the fracture initiation and the
fracture intersection may be determined by other methods, including
measuring, monitoring, recording, etc.
[0015] In addition to knowing the volume of fluid introduced and
the height 36 of the fracture, it may be useful to determine a
fracture length 38 or distance between the initiation location 24
and the intersection location 30. The fracture length 38 may
actually approximate a half-length of the fracture 34. Thus, the
length 38 may not include portions of the fracture 34 extending
from the injection well 10 in a direction away from the observation
well 12. Likewise, the length 38 may exclude portions of the
fracture 34 extending beyond the observation well 12. Determining
the fracture length 38 may be as straightforward as obtaining and
comparing location measurements from the sensor 20 and the sensor
26. Alternatively, fracture length can be estimated using
microseismic monitoring. However, these measurements would likely
be substantially less accurate and more uncertain.
[0016] In another embodiment (not shown), the injection well 10 may
have a deviated portion and the initiation location 24 may be in
the deviated portion of the injection well 10. In such embodiments,
the sensors 20, 26 may register the initiation time and
intersection time and the sensors 20, 26 and/or additional sensors
may further use microseismic data or other techniques allowing for
an estimation of the height 36 of the fracture 34. The same process
may optionally be repeated for additional observation wells (not
shown) with use of additional sensors (not shown). In such
instance, such additional measurement(s) may be obtained in a
similar manner and used to estimate fluid distribution between the
fractures from DAS or other data.
[0017] Once the length 38, height 36, and volume of fluid
introduced are known, a hydraulic fracturing characteristic may be
calculated. For example, a leak-off volume, a leak-off coefficient,
and/or permeability may be calculated. Some such calculations may
involve additional determinations such as fluid pressure in the
fracture, reservoir pressure, viscosity of the fluid, and fluid
compressibility. Other characteristics, such as Young's modulus,
Poisson ratio, complete elliptical integral of the second kind, and
fracture net pressure may be determined and used in the methods
described herein.
[0018] Based on relations of elasticity, leak off volume V.sub.loff
for a long rectangular fracture (L>>h) is
V loff = V inj - V f = .intg. 0 t Q t - .pi. 2 4 1 - v E Lh 2 I ( m
) .DELTA. p ##EQU00001##
[0019] where V.sub.inj is the injected fluid volume, V.sub.f is the
fracture volume at time t, Q is the volumetric injection rate, t is
the time of sensor 26 registering intersection of the fracture 34
with the observation well 12, h is the fracture height 36 (measured
by sensor 30 in the injection well 10), L is the fracture
half-length 38 (equal to the distance between the wells), E is the
Young's modulus .nu. is the Poisson Ratio, I(m) is the complete
elliptical integral of the second kind, .DELTA.p is the fracture
net pressure, and
m = ( h 2 L ) 2 . ##EQU00002##
Leak-off coefficient is calculated as
C L = 3 4 V L L t ##EQU00003##
[0020] Accounting for the connection between the leak-off and flow
properties of the subterranean formation 14 the following constant
can be estimated as well
k .phi. = C L 2 ( p f - p i ) 2 .pi..mu. c t ##EQU00004##
where k is the formation permeability, .phi. is the formation
porosity, p.sub.f is the fluid pressure in the fracture, p.sub.i is
the reservoir pressure, .mu. is the viscosity of the fracturing
fluid and c.sub.t is the fluid compressibility.
[0021] Thus, the method described above may be useful for testing
and/or conducting diagnostics on the subterranean formation 14 and
otherwise aiding in stimulation design and reservoir development
and for estimating reservoir and fracturing characteristics. The
method may be particularly useful for tight formations or other
formations having low hydraulic conductivity and/or low
permeability.
[0022] Various estimated characteristics provided herein may be
used in hydraulic fracturing simulators to history match other
parameters of interest (e.g., stress state and in-situ fracture
toughness). For example, the methodology described may allow for
estimating fracture height and correspondingly the height of the HF
confining zone (if any), the leak-off volume V.sub.L and velocity
.mu..sub.L, the leak-off coefficient C.sub.L, and other formation
flow-related properties.
[0023] Those of skill in the art will appreciate that many
modifications and variations are possible in terms of the disclosed
embodiments, configurations, materials, and methods without
departing from their scope. Accordingly, the scope of the claims
and their functional equivalents should not be limited by the
particular embodiments described and illustrated, as these are
merely exemplary in nature and elements described separately may be
optionally combined.
* * * * *