U.S. patent application number 17/413338 was filed with the patent office on 2022-02-24 for refrac efficiency monitoring.
The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Andrey Vladimirovich FEDOROV, Artem Valeryevich KABANNIK, Roman Vladimirovich KORKIN, Sergey Dmitrievich PARKHONYUK.
Application Number | 20220056793 17/413338 |
Document ID | / |
Family ID | 1000005998789 |
Filed Date | 2022-02-24 |
United States Patent
Application |
20220056793 |
Kind Code |
A1 |
KORKIN; Roman Vladimirovich ;
et al. |
February 24, 2022 |
REFRAC EFFICIENCY MONITORING
Abstract
A method of treatment of a subterranean formation penetrated by
a wellbore, where the well has a plurality of previously stimulated
intervals includes: a) pumping a viscous pill into a well with
pressure curve registration by a wellhead pressure sensor; b)
determining a depth (L) of treatment fluid entry point and depth
uncertainties (L); c) generating a water hammer at the wellhead
which excites tube waves; d) determining the depth (L) of the
treatment fluid entry point and the depth uncertainties (L) by
processing a water hammer by high frequency pressure monitoring
method; e) determining a tube wave velocity from a combination of
data from (b) to (d); f) performing a fracturing treatment; and g)
generating a water hammer at the wellhead at the end of the
fracturing treatment (f) with refined depth of treatment fluid
entry point and with lower uncertainty.
Inventors: |
KORKIN; Roman Vladimirovich;
(Novosibirsk, RU) ; PARKHONYUK; Sergey Dmitrievich;
(Novosibirsk, RU) ; FEDOROV; Andrey Vladimirovich;
(Novosibirsk, RU) ; KABANNIK; Artem Valeryevich;
(Novosibirsk, RU) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Sugar Land |
TX |
US |
|
|
Family ID: |
1000005998789 |
Appl. No.: |
17/413338 |
Filed: |
December 12, 2018 |
PCT Filed: |
December 12, 2018 |
PCT NO: |
PCT/RU2018/000815 |
371 Date: |
June 11, 2021 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 47/00 20130101;
E21B 43/26 20130101 |
International
Class: |
E21B 43/26 20060101
E21B043/26; E21B 47/00 20060101 E21B047/00 |
Claims
1. A method of treatment of a subterranean formation penetrated by
a wellbore, wherein the well has a plurality of previously
stimulated intervals comprising: a) pumping a viscous pill into a
well with pressure curve registration by a wellhead pressure
sensor; b) determining a depth (L) of treatment fluid entry point
and depth uncertainties (.DELTA.L); c) generating a water hammer at
the wellhead which excites tube waves; d) determining the depth (L)
of the treatment fluid entry point and the depth uncertainties
(.DELTA.L) by processing a water hammer by high frequency pressure
monitoring method; e) determining a tube wave velocity from a
combination of data from (b) to (d); f) performing a fracturing
treatment; and g) generating a water hammer at the wellhead at the
end of the fracturing treatment (f) with refined depth of treatment
fluid entry point and with lower uncertainty.
2. The method of claim 1, wherein multiple stimulation treatments
are pumped in the well.
3. The method of claim 1, wherein the data frac treatment is
performed before pumping a viscous pill.
4. The method of claim 1, wherein the viscous pill is a portion of
fluid with a viscosity of at least 100 times higher than a
viscosity of a wellbore fluid.
5. (canceled)
6. The method of claim 1, wherein the water hammer is generated by
shutdown of pumps at the surface.
7. The method of claim 1, wherein the high frequency pressure
monitoring method comprises processing of a pressure signal.
8. The method of claim 7, wherein processing of the pressure signal
comprises preliminary signal filtering.
9. The method of claim 7, wherein processing of the pressure signal
further comprises processing with cepstrum analysis.
10. The method of claim 1, wherein a diverter is additionally
pumped into the wellbore after (g).
11. (canceled)
12. (canceled)
13. The method of claim 1, wherein the depth determination (L) has
a resolution of at least 100 ft (30.48 m).
14. (canceled)
15. The method of claim 1, further comprising performing a
completion operation, wherein the completion operation is selected
from the group of plug-and-perf completions or slide and sleeve
completions.
Description
BACKGROUND
[0001] Hydrocarbons (oil, natural gas, etc.) are obtained from a
subterranean geologic formation (i.e., a "reservoir") by drilling a
wellbore that penetrates the hydrocarbon-bearing formation. This
provides a partial flowpath for the hydrocarbon to reach the
surface. In order for the hydrocarbon to be "produced," that is
travel from the formation to the wellbore (and ultimately to the
surface), there is a sufficiently unimpeded flowpath from the
formation to the wellbore.
[0002] Fractures in earth formations are of major significance in
the production of subsurface fluid resources such as hydrocarbons.
In formations of low permeability and low porosity, the potential
production from a borehole into the formation is directly related
to the number of open fractures. Secondary recovery of hydrocarbons
after production by the formation's inherent fluid pressure has
been exhausted often involves the injection of fluids to move
hydrocarbons towards a producing well, and knowledge of the
fractures in the formation is valuable in predicting the overall
recovery.
[0003] Hydraulic fracturing is the method of well stimulation by
generating fractures inside hydrocarbon-bearing formation in which
fractures are created by means of pumping fluid and propping agent
downhole at high pressure. The main objective of fracturing is to
increase well productivity and fracturing and acidizing jobs to
increase formation permeability may be designed based on reservoir
data, proppant, acid volume to be pumped, target productivity index
of the well, and the like. However, the difficulty in
characterizing the effectiveness of a hydraulic fracturing
treatment can introduce a certain degree of uncertainty as to the
total amount of hydrocarbon recoverable from a given reservoir.
SUMMARY
[0004] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify key or
essential features of the claimed subject matter, nor is it
intended to be used as an aid in limiting the scope of the claimed
subject matter.
[0005] In one aspect, embodiments disclosed herein relate to a
method of treatment of a subterranean formation penetrated by a
wellbore, where the well has a plurality of previously stimulated
intervals includes: a) pumping a viscous pill into a well with
pressure curve registration by a wellhead pressure sensor; b)
determining a depth (L) of treatment fluid entry point and depth
uncertainties (.DELTA.L); c) generating a water hammer at the
wellhead which excites tube waves; d) determining the depth (L) of
the treatment fluid entry point and the depth uncertainties
(.DELTA.L) by processing a water hammer by high frequency pressure
monitoring method; e) determining a tube wave velocity from a
combination of data from (b) to (d); 0 performing a fracturing
treatment; and g) generating a water hammer at the wellhead at the
end of the fracturing treatment (f) with refined depth of treatment
fluid entry point and with lower uncertainty.
[0006] Other aspects and advantages of the claimed subject matter
will be apparent from the following description and the appended
claims.
BRIEF DESCRIPTION OF DRAWINGS
[0007] FIG. 1 shows variation of pressure versus time in accordance
with embodiments of the present disclosure.
[0008] FIG. 2 shows a cepstrogram in accordance with embodiments of
the present disclosure.
[0009] FIG. 3 is a flow diagram illustrating a treatment in
accordance with embodiments of the present disclosure.
[0010] FIG. 4 depicts the variation of pressure versus time for
viscous pill pumping in accordance with embodiments of the present
disclosure.
[0011] FIGS. 5 and 6 are graphical representations illustrating
refracturing monitoring processes in accordance with embodiments of
the present disclosure.
DETAILED DESCRIPTION
[0012] Generally, embodiments disclosed herein relate to methods of
monitoring refracturing effectiveness of previously stimulated
subterranean formations to improve well performance and recovery of
hydrocarbons. More specifically, embodiments disclosed herein
relate to methods for monitoring, controlling, evaluating and
improving the refracturing effectiveness in a well with multiple
previously stimulated stages. In some embodiments, methods may also
include performing one or more remediation actions to modify a
treatment design in real-time. The inventors of the present
disclosure have discovered that using the viscous pill technology
combined with high frequency pressure measurement with water hammer
generation may provide real-time information regarding the
refracturing effectiveness of a subterranean formation with higher
accuracy and robustness and lower price and within shorter period
of time than when only one of the technologies is used. The higher
accuracy of the refracturing effectiveness achieved as described
herein may allow for restimulation of more stages (than with the
use of viscous pill technology only for example) with the minimal
risk of understimulation of some stages and overstimulation of
others.
[0013] As defined herein, understimulation may be understood as
hydraulic or acid fracturing. Furthermore, as defined herein, the
term "stage" or "interval" defines an element of wellbore
completion that enables the possibility of performing a fracturing
operation (treatment) in this place. In addition, a multistage
treatment (a multistage frac) is defined as the consecutive
(stage-by-stage) fracturing operations. All these definitions may
be found in the Schlumberger Oilfield Glossary.
[0014] Methods in accordance with the present disclosure may be
used to monitor the effectiveness of refracturing treatments in a
well that has a plurality of previously stimulated stages. Such
methods may be applied for monitoring the effectiveness of a
secondary or a tertiary stimulation treatment with the purpose of
providing real-time information regarding the refracturing
effectiveness of each stage stimulation. Such information may help
an operator to make a decision, such as whether the given
production stage is already effectively stimulated or whether
isolation of other stages should be performed with the further
restimulation of a given stage.
[0015] According to the present embodiments, the method of
monitoring refracturing effectiveness combines viscous pill (VP)
technology, i.e. pumping of a marker viscous fluid (with a high
viscosity, degradable with time) and high frequency pressure
measurement (HFPM) with water hammers generation at the end of the
treatment stage and their further processing.
[0016] In practice, the viscous pill technology may allow for
identification of a position of a fracture produced during a
hydraulic fracturing stimulation of a formation. Such a method is
based on the local change of the viscosity and/or density of the
liquid being pumped into the well and includes pumping a fracturing
fluid into the wellbore at a pressure above the fracture pressure
of the formation to create at least one fracture. Afterwards, a
marker pulse is pumped into the well, followed by pumping
fracturing fluid back into the well. At the entrance of the marker
pulse to at least one of the hydraulic fractures, a pressure
detectable response is observed, and the position of the fracture
is determined by the volume of fracturing fluid injected after the
marker pulse. The marker pulse is a portion of a liquid exhibiting
different viscosity and/or density of the fracturing fluids
injected before and after the marker pulse. Examples of viscous
pill technology are discussed in greater detail in WO Publication
No. 2018/004370A1.
[0017] As noted above, the viscous pill technology may be combined
with high frequency pressure measurement (HFPM) with water hammers
generation. In one or more embodiments, the high frequency pressure
measurement (HFPM) may involve a cepstrum analysis. For example, WO
Publication No. 2018/004369A1 discusses in greater detail a method
of monitoring the well operations based on cepstrum analysis of
downhole pressure data recorded at the wellhead. The method is
designed to locate a downhole object which reflects a hydraulic
signal. According to such a method, a well is filled with a fluid
medium that permits the passage of a hydraulic signal. A hydraulic
signal source is provided, which is in communication with the well
via the fluid medium and is designed to generate a hydraulic
signal. A pressure transmitter is designed to register the
hydraulic signal and is in communication via the fluid medium, with
the well and with at least one hydraulic signal source. A hydraulic
signal is registered using a pressure sensor, and a pressure
cepstrogram is generated, highlighting an intense signal on the
pressure cepstrogram. Afterwards, the object which reflects the
hydraulic signal is located.
[0018] According to one or more embodiments, the method of
treatment of a subterranean formation penetrated by a wellbore,
such as a refracturing monitoring method, involves the use of
sequential viscous pill pumping (and depth determination), high
frequency pressure monitoring of water hammers (at the end of
viscous pill also for depth determination) and diverter to plug the
stages with the highest fluid acceptance, with additional high
frequency pressure monitoring at the end of the diverter pumping.
The combination of these methods may allow, for example, reliable
determination whether a diverter works well, or if more diverter
should be pumped. Moreover, the amount of viscous pill pumped may
be reduced due to additional data received from the high frequency
pressure monitoring. As a result, the treatment may be performed
faster and with reduced cost. The higher accuracy of the diversion
effectiveness achieved with the use of the two technologies may
also allow restimulation of more stages (than with the use of
viscous pill technology only) with a reduced (or even minimal) risk
of understimulation of some stages and overstimulation of
others.
[0019] According to the present embodiments, the refracturing
operation is performed in a well, which has been previously
stimulated and has a plurality of previously stimulated intervals,
but in which hydrocarbon production dropped and thus a new
stimulation (or restimulation or refracturing) is considered as
feasible. In one or more embodiments, the refracturing operation is
performed in a specific sequence of stages as described below. In
such embodiments, a first stage of the stimulation treatment is to
determine which of previously stimulated stages in the well are
accepting fluids, followed by alternate stages of stimulation
treatment (such as a hydraulic fracturing treatment) with the
formation of new fracture(s) and isolation of such fracture(s)
using diverters. The sequence of the steps is repeated until all
stages planned for stimulation are stimulated (or earlier if design
will be re-considered). Data may be collected and processed to
evaluate the effectiveness of the stimulation treatment and to
determine future stimulation treatments.
[0020] According to the present embodiments, the fluid used as a
stimulation fluid can be of any type. It is also assumed that in
some embodiments the properties of the fluid remain the same during
the whole treatment process. It is also envisioned that in some
embodiments the properties may change from one stimulation to
another; in such embodiments, the difference may be taken into
account by using correction coefficients on the tube waves velocity
based on the fluid properties knowledge. In one or more
embodiments, the properties of the fluid may be unknown or poorly
determined. In such embodiments, a more viscous pill may be
pumped.
[0021] According to one or more embodiments of the present
disclosure, the refracturing operation of a well with multiple
stages may include the following sequence of stages: [0022] 1.
Pumping fluid according to a stimulation design to create a first
fracture. The fracture may appear in any of 1 . . . N stages
available in a well. [0023] 2. Isolating the created fracture by
using a chemical (dissoluble) diverter, i.e., a fluid with
specially designed particles, which may plug the opened fracture.
[0024] 3. Pumping fluid according to the stimulation design to
create a second fracture. The second fracture may appear in any of
1 . . . N stages available in a well. If a fracture is formed in a
new production stage, the stimulation is considered successful. If
a new fracture has not been formed and the fluid was pumped to a
first fracture, then the new stage is unstimulated, and stimulation
failed. The timely detected stimulation failure may be used in
order to update the stimulation schedule, for example, to repeat
the isolation step of already stimulated stages, then change the
concentration of additives in the diverter pill, followed by
adjusting the pill volume, then making changes in the fracturing
treatment design such as adjusting the volume of a fluid pumped for
fracture growth, or adjusting the proppant/fibers concentration.
[0025] 4. Isolating both of the existing fractures. [0026] 5.
Performing a new stimulation treatment.
[0027] As noted above, the sequence of the steps is repeated until
all stages planned for stimulation are stimulated (or earlier if
design will be re-considered). The challenge is to predict whether
the stimulation of a stage is successful, or if the fluid is pumped
to already existing fractures. With the development of modeling,
software, and hardware capacities, the ability to optimize designs
before a treatment stage and in real-time has become more feasible.
Currently, there are several methods of fluid entry point
identification during refracturing, such as Distributed Temperature
Sensing (DTS), Distributed Vibration Sensing (DVS), radioactive and
chemical tracers, and microseismic technology. However, such
approaches have numerous limitations and therefore the information
provided has high measurement uncertainty that can limit the
reliability of predictions.
[0028] DTS method involves pumping a large volume of cold fluid and
long-term measurements of temperature distribution along the
wellbore. DVS is very sensitive to a small volume of gases, as gas
bubbles may cause false vibrations. The microseismic method works
well only in mechanically solid formations and depends on the
monitoring of well location vs. treated well. Moreover, the
microseismic technology is not a near-wellbore method and is
sensitive to events which occur few hundred feet away from the
wellbore. Thus, the vertical depth in the wellbore is not
accurately known. The presence of chemical or radioactive tracers
shows rather high permeability zones of the formation, which may or
may not relate to the fracture. Vice versa, the absence (or a
concentration below the background) of chemical or radioactive
tracers in the near well bore zone may mean that the particles were
pumped deeply into the formation. At last, these methods are not
popular due to HSE reasons.
[0029] Another method, which is widely used due to its simplicity
and low cost is surface pressure monitoring. In such a case, the
fluid entry point is not measured; instead, the diversion
efficiency is monitored by the Instantaneous Shut in Pressure
(ISIP) change method: the diversion is considered successful if the
ISIP after stimulation exceeds ISIP after previous stimulation.
Unfortunately, this method doesn't guarantee the accuracy of the
results. In addition, the ISIP computation may take time and still
may be determined with a certain degree of uncertainty. Thus, the
difference between current and previous ISIPs should exceed a
minimum threshold, which is subjective. Moreover, the negative
difference between ISIPs doesn't mean poor diversion, the friction
pressure losses should also be estimated: if it is increased from
the previous stimulation, then the diversion is also successful
regardless the ISIPs difference (friction pressure may be higher
for formations with lower ISIP due to friction losses in the
damaged near-wellbore zone).
[0030] Another method of fluid entry point identification is the
viscous pill technology. When a viscous pill is pumped into a well
an increase in pressure may be observed when the pill enters into
the fracture. Using well completion data, pumping rate, and the
time when fluid reaches fracture, the depth of fluid entry point
may be predicted. However, in many cases this depth may be
predicted with the accuracy comparable to the distance between
stimulated stages and therefore may not give precise results.
Moreover, pumping a viscous pill at the end of each stage may not
be cost-effective and may involve a longer additional time. For
these reasons, the viscous pill technology alone is not very widely
used.
[0031] Without being bound by the theory, it was found by the
present inventors that the drawback of using viscous pill
technology may be overcome by combining such technology with high
frequency pressure measurements. Such a combination may allow for
monitoring the effectiveness of a refracturing treatment. In one or
more embodiments, methods may utilize viscous pill technology,
i.e., pumping of a viscous fluid (1000 and more cP at 100 s.sup.-1
during at least 20 min with fast viscosity degradation down to 100
cP or less) and of high frequency pressure measurement with water
hammers generation at the end of job and their further
processing.
[0032] As described herein, high frequency pressure measurement is
based on the analysis of water hammer signals (or tube waves)
propagating in a wellbore. Tube waves are interface waves that
occur in cased wellbores when a Rayleigh wave encounters a wellbore
and perturbs the fluid in the wellbore. The tube wave travels down
the wellbore along the interface between the fluid in the wellbore
and the wall of the wellbore. Because the tube wave is coupled to
the formation through which it is traveling, it can perturb the
formation across open fractures intersecting the borehole, creating
a squeezing effect that generates secondary tube waves that are
reflected up and down from the fracture location. Intercepted
secondary tube waves may contain signatures diagnostic of open
fractures and their amplitude related qualitatively to the length
and width, e.g., volume of the fluid-filled fracture space, in
addition to other characteristics such as fracture closure
pressure, fracture initiation pressure, and the like. Tube waves
may also be used to detect other features such as obstructions,
pipe sections of different diameters, perforations, and open
fractures.
[0033] In practice, secondary tube waves may be deconvolved from
primary tube waves by identifying the time and magnitude of the
peak value of the envelope of the deconvolved signal. This time and
magnitude will vary in a predictable manner, and the variation can
be analyzed as a function of depth. Advanced algorithms for tube
wave processing (e.g., cepstrum analysis as previously discussed)
together with pressure source control mechanisms, including pump
noise, active pulse sources, and the like, may also be used to
extract date from tube waves to resolve positions of multiple
fractures from a wellbore.
[0034] According to the present disclosure, high frequency pressure
measurement may allow computing period of water hammers (or tube
waves) generated at the end of each stage (or even between the
stages, when the pumping rate changes very fast). These periods
relate to the time required by tube waves for traveling from the
wellhead to the fracture and being reflected from the fracture
back. Periods (or reflection times) can be converted into the
depths if the tube waves velocity is accurately known, which is not
the common case. To predict this velocity, some other information
may be involved for calibration. One of the methods is the use of a
fluid entry point predicted by the viscous pill technology. In this
case, a combination of time and depth provides a good estimation
for the velocity (at least in a given stimulation stage). The
reasonable assumption that the velocity doesn't change too much
between the nearest stages, as well as the use of other methods as
described later may give information on whether all of the stages
are stimulated or not. The information may be obtained at the end
of each stage and may be used by an operator to adjust stimulation
design for further stages.
[0035] According to one or more embodiments, a method of treating a
subterranean formation penetrated by a wellbore may include: a)
pumping a viscous pill into a well with pressure curve registration
by a wellhead pressure sensor; b) determining a depth (L) of
treatment fluid entry point and depth uncertainties (.DELTA.L); c)
generating a water hammer at the wellhead which excites tube waves;
d) determining the depth (L) of the treatment fluid entry point and
the depth uncertainties (.DELTA.L) by processing a water hammer by
high frequency pressure monitoring method; e) determining a tube
wave velocity from a combination of data from (b) to (d); f)
performing a fracturing treatment and g) generating a water hammer
at the wellhead at the end of the fracturing treatment (f) with
refined depth of treatment fluid entry point and with lower
uncertainty. In such embodiments, the well has a plurality of
previously stimulated intervals. In one or more embodiments,
multiple stimulation treatments may be pumped in the well.
[0036] According to one or more embodiments, the data frac
(https://petrowiki.org/Glossary) treatment may be performed before
pumping a viscous pill into the well. In such embodiments, the
viscous pill may be a portion of fluid with a viscosity of at least
100 times higher than a viscosity of the wellbore fluid. In one or
more embodiments, where multiple stimulation treatments are
performed, the viscous pill is pumped before each fracturing
treatment. In such embodiments, the water hammer may be generated
by shutting down the pumps at the surface. In one or more
embodiments, the high frequency pressure monitoring method involves
processing a pressure signal, for example including preliminary
signal filtering and further processing with cepstrum analysis. It
is also envisioned that a diverter may be additionally pumped into
the wellbore after stage (g). In such embodiments, the diverter may
be a portion of particle slurry capable to isolate at least one of
previously stimulated intervals. In one or more embodiments, the
diverter may be selected from the group of chemical (dissoluble)
and mechanical diverters.
[0037] In one or more embodiments, the method of treatment of a
subterranean formation may further comprise performing a completion
operation. In such embodiments, the completion operation is
selected from the group of plug-and-perf completions or slide and
sleeve completions.
[0038] It is also envisioned that the method of treating a
subterranean formation penetrated by a wellbore may include 1)
pumping a first viscous pill into a well located in the
subterranean formation, where the well has a plurality of
previously stimulated stages, 2) determining a depth (L) of
treatment fluid entry point and a depth uncertainty (.DELTA.L) for
which of the previously stimulated stages are accepting fluid, 3)
generating a water hammer at the wellhead to excite tube waves, 4)
processing the water hammer by high frequency pressure monitoring
method to determine the depth (L) of the treatment fluid entry
point and the depth uncertainty (.DELTA.L), 5) determining a tube
wave velocity by combining 2)-4), 6) performing a first stimulation
treatment (such as a fracturing treatment) in the at least one
previously stimulated stage that is accepting fluid to form a first
new fracture in the at least one previously stimulated stage, 7)
generating a water hammer at the wellhead at the end of the
fracturing treatment 6) with refined depth of the treatment fluid
entry point and with lower uncertainty, 8) isolating the first new
fracture by pumping a diverter, 9) computing at least a reflection
time of water hammers and a reflection time uncertainty by using a
high frequency pressure monitoring with water hammers generated at
least at the end of one treatment stage, 10) predicting a tube wave
velocity for the at least one previously stimulated (fractured)
stage using at least the depth of fluid entry point (L) and the
reflection time of water hammers, and 11) evaluating the
effectiveness of the first stimulation treatment to determine
future stimulation treatments, if any. In one or more embodiments,
determining the depth (L) of fluid entry point and the depth
uncertainty (.DELTA.L) of the at least one previously stimulated
stage is performed by viscous pill technology, high frequency
pressure monitoring, or a combination thereof. In such embodiments,
the depth (L) determination may have a resolution of at least 100
ft (30.48 m). In one or more embodiments, the maximum measured
depth of at least a fracture may be up to 40000 ft (12192 m). It is
also envisioned that multiple viscous pills and high frequency
water hammers may be used during the first stimulation treatment
stage.
[0039] It is also envisioned that a second viscous pill may be
pumped into the well after isolating the first new fracture
(achieved by pumping a diverter). The next stage is to verify
whether the previously stimulated stages that are accepting fluid
shift compared to an original value. If there is an indication that
the first stimulation treatment was effective, and no additional
amount of diverter is necessary, a second stimulation treatment at
a second stage may be performed.
[0040] In such an embodiment, a second stimulation treatment in the
at least a second previously stimulated stage that is accepting
fluid to form a second new fracture is performed, followed by
isolating the second new fracture by pumping a diverter, computing
at least a reflection time of water hammers and a reflection time
uncertainty by using a high frequency pressure monitoring with
water hammers generated at least at the end of one treatment stage,
predicting a tube wave velocity for the at least a second
previously stimulated stage using at least the depth of fluid entry
point and the reflection time of water hammers and evaluating the
effectiveness of the second stimulation treatment to determine
future stimulation treatments, if any.
[0041] It is also envisioned that when the first stimulation
treatment is ineffective, an additional amount of diverter may be
pumped. In such embodiments, the amount of the diverter may be
adjusted (increased or decreased) based on the effectiveness of the
refracturing. As described herein, the diverter may be selected
from the group of chemical (dissoluble) and mechanical diverters.
In such embodiments, a second isolation treatment on the at least
one previously stimulated stage may be performed.
[0042] As noted above, the sequence of these treatment stages is
repeated until all stages planned for stimulation are stimulated
(or earlier if design will be re-considered). After the stimulation
is performed, the next treatment stage is a completion operation.
In such embodiments, the completion operation may be selected from
the group of plug-and-perf completions or slide and sleeve
completions.
[0043] It is also envisioned that the method of treating a
subterranean formation is a method of stimulating a subterranean
formation penetrated by a wellbore. In such illustrative
embodiments, the method includes pumping a first viscous pill into
a well located in the subterranean formation, where the well has a
plurality of previously stimulated stages, performing a first
stimulation treatment with the formation of a first new fracture in
at least one previously stimulated stage that is accepting fluid,
generating water hammer at the end of the fracturing treatment with
refined depth of the treatment fluid entry point and with lower
uncertainty and adjusting future stimulating treatment(s) according
to processed input data collected during various treatment
stages.
[0044] As noted above, the depth determination may have a
resolution of at least 100 ft (30.48 m). In one or more
embodiments, the maximum measured depth of at least a fracture is
up to 40000 ft (12192 m).
[0045] According to one or more embodiments, multiple viscous pills
and high frequency water hammers may be performed during a first
stimulation treatment stage.
[0046] It is also envisioned that a second viscous pill may be
pumped into the well after isolating the first new fracture by
pumping a diverter. The next stage is to verify whether the
previously stimulated stages that are accepting fluid shifted
compared to an original value. If there is an indication that the
first stimulation treatment was effective, and no additional amount
of diverter is necessary, a second stimulation treatment at a
second stage may be performed.
[0047] In such an embodiment, a second stimulation treatment in the
at least a second previously stimulated stage that is accepting
fluid to form a second new fracture is performed, generating water
hammer at the end of the fracturing treatment with refined depth of
the treatment fluid entry point and with lower uncertainty and
adjusting future stimulating treatment(s) according to the
processed input data collected during various treatment stages.
[0048] It is also envisioned that when the first stimulation
treatment is ineffective, an additional amount of diverter may be
pumped. As described herein, the diverter may be selected from the
group of chemical (dissoluble) and mechanical diverters. In such
embodiments, a second isolation treatment on the at least one
previously stimulated stage may be performed.
[0049] As noted above, the sequence of these treatment stages is
repeated until all stages planned for stimulation are stimulated
(or earlier if design will be re-considered). After the stimulation
is performed, the next treatment stage is a completion operation.
In such embodiments, the completion operation may be selected from
the group of plug-and-perf completions or slide and sleeve
completions.
[0050] High Frequency Pressure Measurement
[0051] The use of a high frequency (at least 20 or 30 Hz) pressure
measurement technology may allow obtaining much more information
than the standard pressure metering. The fast flowrate changes from
maximum to zero at the end of pumping may cause water hammers (or
tube waves) to travel from the wellhead down to the fracture and
back. The reflection time of these waves (typically, between 3 and
10 sec) may indicate the depth of the open fracture and generally
may be used for the fluid entry point determination. These
oscillations may contain other parameters besides the oscillation
components, such as attenuation, pressure friction losses, fluid
leakage to the formation, noise, or reflection from other elements
in the wellbore. Thus, the reflection time may be difficult to be
determined. However, various methods are developed for determining
such parameters. For example, cepstrum analysis as represented
below in FIG. 2, may be used for the reflection time
measurement.
[0052] Referring now to FIGS. 1 and 2, FIG. 1 depicts a typical
high frequency pressure curve during water hammer. Its cepstrogram
is shown in FIG. 2. Specifically, FIG. 1 depicts a pressure
oscillation at the end of pumping, while FIG. 2 depicts a
cepstrogram, i.e. "amplitudes" of waves with different reflection
time as a function of time. Referring to FIG. 2, 200 represents the
strongest amplitude, i.e., main pressure wave reflections from the
fracture, while 210, represented as a line, depicts the reflection
time. The width of 210 determines its uncertainty.
[0053] In most cases, the tube wave velocity is unknown and
reflection time itself is useless. Despite this, it may be possible
to apply the special algorithm for velocity determination. In one
or more embodiments, this can be described based on a plug and perf
completion example, but it may be extended to all other cases. It
is assumed that there are only N available stages, where the
fractures can be potentially formed.
[0054] The depths of these stages are L.sub.1 . . . L.sub.N, and
the depth's uncertainty is .sigma.L.sub.1 . . . .sigma.L.sub.N. In
a normal case, when the stage has a width, .DELTA.L.sub.i, the
uncertainty, .sigma. L.sub.i, can be computed as an uncertainty for
the uniform distribution and is defined by formula 1:
.sigma. .times. L i = 1 2 .times. 3 .times. .DELTA. .times. L i ( 1
) ##EQU00001##
[0055] The first fracture may be located at the first stage only
(whose depth and depth uncertainty are known), as there are no
other perforations. This allows the first stage velocity
calculation and its associated uncertainty determination to be
made. This data can be used as a first guess for the second stage
velocity calculation, which combined with the reflection time of
the events (such as water hammers) after the second stage
treatment, may predict the possible depth of the second stage's
fracture. Further, this predicted depth is compared with the
perforation depth of the second stage (if the mechanical isolation
is successful) and perforation depth of the first stage (if the
mechanical isolation is a failure/leak). The difference between the
predicted depth and available stage's depth cannot exceed two to
three sigma values, where sigma is a standard deviation (or
uncertainty) of the difference, which can also be computed. This
allows for prediction of whether or not the second stimulation was
successful, and it may provide a probability of the successful
stimulation if both scenarios occur.
[0056] Moreover, for each of these scenarios, the velocity may be
defined with higher accuracy when information from more than one
stage is available, for example data from the first and second
stage pumping operations. A similar principle may be used for
subsequent events (stimulations). Some advanced statistical methods
(including Bayesian techniques) may allow for the prediction of
each treatment fracture location considering each available
scenario more precisely as more measurements are recorded, tuning
velocity value and its slow change along the lateral.
[0057] At any stage, more than one scenario may exist, but all of
them have their own probability p, which are based on the maximum
likelihood method as described by formula 2:
p .function. ( i .times. 1 , i .times. 2 , .times. .times. in ) ~
exp .function. ( - ( D 1 - L i .times. 1 ) 2 2 .times. ( .sigma.
.times. D 1 2 + .sigma. .times. L i .times. 1 2 ) ) * exp
.function. ( - ( D 2 - L i .times. 2 ) 2 2 .times. ( .sigma.
.times. D 2 2 + .sigma. .times. L i .times. 2 2 ) ) .times. .times.
.times. .times. exp .function. ( - ( D n - L in ) 2 2 .times. (
.sigma. .times. D n 2 + .sigma. .times. L in 2 ) ) ( 2 )
##EQU00002##
[0058] Finally, the number of possible scenarios may be very large
if the data for each event is very inaccurate (high values of
.sigma..tau..sub.i and .sigma.L.sub.i--reflection time and depth
uncertainties) and/or there are only few events. Vice versa, this
number may be small (just a few, or even one) if the reflection
times are determined accurately and the stage width is small
compared to the distance between them and the total number of
stimulations is high enough.
[0059] Viscous Pill Technology and High Frequency Pressure
Measurements
[0060] According to the present embodiments, viscous pill
technology and high frequency measurements may be used together.
Such a combination may allow performing the refracturing monitoring
faster, with a high level of confidence, in a short time and with
minimum resources. In such embodiments, the monitoring is performed
as follows: [0061] 1. Pump a viscous pill and determine a fluid
entry point with uncertainty. Assign this fluid entry point to one
of few stages with their own probabilities. The number of possible
scenarios, where the fracture will be created is less or equal to
the total number of stages. [0062] 2. Perform the first stimulation
treatment. Using water hammers at the end of the treatment stage
may allow for determination of the reflection time and uncertainty.
Using the depths of possible stages and the reflection time
obtained may predict velocity for each of the stages determined
above at point 1. [0063] 3. Pump diverter. At the end of the
diverter pumping use water hammers to receive a new reflection time
which combined with the velocity for each of the possible scenarios
may predict a new depth. This is further compared with all the
possible stage depths where the second fracture may go. [0064] 4.
Generate a new set of scenarios with their probabilities, which are
proportional to the product of probabilities from points 1 and 3
above. After normalization, the scenarios with probabilities less
than a predefined threshold (for example 0.5% or 0.01 of the most
probable scenario) may be removed from the consideration. [0065] 5.
If the number of scenarios is more than one, depending on their
relative probabilities, time and resources restrictions, the new
diverter may be pumped or not. [0066] 6. Perform the second
stimulation. Using water hammer at the end of a treatment stage may
determine reflection time and uncertainty. Using the data of all
existing scenarios, compare the predicted depth of the second
fracture shown in formula 3
[0066] v 2 .times. .tau. 2 2 ( 3 ) ##EQU00003##
with all possible stages to evaluate where it may be located (here
velocity and reflection time are used, coefficient 1/2 comes from
the travel path: wellhead-bottomhole and back). If the location of
a fracture differs from the location of a previous fracture, the
stimulation may be considered as successful and the velocity may be
updated using all data available as should be similar and, for
example, the real velocity at each stage may be computed as
described in formula 4:
v n = 2 .times. i = 1 N .times. w i .times. D i .times. .tau. i i =
1 N .times. w i .times. .tau. i 2 , ( 4 ) ##EQU00004##
where .tau..sub.i--reflection time of i-th event, D.sub.i is the
calculated depths of a fracture, corresponding to this event,
weights w.sub.i represent weights of events (the higher event
reflection time and depth uncertainty, the smaller its weight). The
new probability for all scenarios is computed as a normalized
product of probabilities determined at 1, 3, 5, 6. However, it is
not the common case that only one scenario remains at this stage
even if the stimulation is evaluated as successful. In fact, there
might be few scenarios if in each of them the first stage differs
from the second stage. If the stimulation failed in some of the
scenarios, the probability of failure should be evaluated as
described by formula 5:
1-.SIGMA..sub.i=1.sup.Np.sub.i*(1 if successful divertion) (5)
If the probability of failure is high enough, further actions may
be performed, such as a new event generation (start and stop
injection, open or close valve, etc.). For example, in such a case,
its water hammer may be analyzed, and used in all re-evaluation
scenarios. If the probability failure is still high, further
actions such as new viscous pill pumping, its depth evaluation,
scenarios re-evaluation, etc. may be performed. If the failure is
still probable, pumping an additional diverter may be performed.
[0067] 7. Pump a new diverter. Re-evaluate all scenarios. [0068] 8.
Perform a third stimulation treatment. Using water hammer at the
end of the treatment stage may allow for determination of
reflection time and uncertainty. Using the data, re-evaluate all
scenarios to make a solution on the stimulation efficiency of all
three stimulations. [0069] 9. Continue the stimulation
treatment.
[0070] This flow chart of on-site decision making is shown in FIG.
3. Such a flow chart may allow for performing a refracturing
operation in a well having multiple stimulation stages much faster
than with currently used methods, with reduced resources, while
providing more reliable information regarding the effectiveness of
the stimulation treatment for each stage.
Examples
[0071] The following examples are presented to further illustrate
the refracturing monitoring method in accordance with the present
disclosure and should not be construed to limit the scope of the
disclosure, unless otherwise expressly indicated in the appended
claims.
[0072] For comparative purposes, a classic viscous pill technology
was used. The classic viscous pill technology (without high
frequency pressure monitoring) involves the following sequence of
stages: [0073] 1. Mixing the pill with the use of a linear gel and
a crosslinking agent. [0074] 2. Pumping approximately 3-4 m.sup.3
of the viscous pill (with the viscosity at least 100 times higher
than the viscosity of wellbore fluid) at a low flowrate. The first
viscous pill is pumped into a well following the injection test.
Such a pill is used to identify the most fluid-accepting stage.
Identification is done by the pressure monitoring and analysis. The
surface pressure slope should increase at the point when a viscous
pill enters a fracture. [0075] 3. Performing a first stimulation
stage. [0076] 4. Pumping a diverter (isolation agent) into the
wellbore. [0077] 5. Pumping a second viscous pill to verify whether
the fluid accepting point shifted compared to the original value
(position of diverter isolation action). Depending on the result
(if diverter fails), the additional amount of chemical (dissoluble)
diverter may be pumped, or other actions can be done in agreement
with the client. [0078] 6. When the diversion is achieved, the
second stimulation (fracturing) is performed, and the treatment
continues the same way from one stimulation stage to another.
[0079] The method of fluid entry point determination may assume the
search of an optimal point of intersection of two (almost) linear
parts of the pressure-time curve with its statistical processing.
This point of intersection combined with the wellbore completion
data and pumping rate provides fluid entry point depth. The stage
that accepts fluid is predicted by comparison with the depths of
various stages.
[0080] A typical pressure curve with the analysis of fluid entry
point determination is shown in FIG. 4. Referring to FIG. 4, FIG. 4
depicts the identification or marker pill as described in WO
Publication No. 2018/004370. As seen in FIG. 4, a slope change from
a small inclination to a high one determines the time of viscous
pill entering the open fracture (since the pumping starts). The
result gives 17.7+/-0.3 min. For the typical velocity of a pill
travel in a liner .about.2 m/s, this causes the error in depth
estimation about 36 m, which is comparable with the typical
distance between stages. Thus, the viscous pill positioning with
this accuracy doesn't guarantee a reliable answer for all treatment
stages.
[0081] A two-stages of re-fracturing was performed in a well. The
well itself contains 4 stages (perforations separated by packers).
The first stimulation was performed as a data frac in order to
obtain general formation properties (pressure decline curve
analysis) and determine which stage is the most accepting fluid
(with the use of high frequency pressure monitoring). The data frac
(or pre-frac) operation is defined as a pumping of moderate amount
of clean fracturing fluid at the pressure above the reservoir
fracturing pressure for gathering of information about the
mechanical properties of rock--this evaluation is needed for more
accurate predicting of later full-scale fracturing operation
(herein--stimulation). Since information about the tube wave
velocities (except physical restrictions for wellbore fluid from
1300 m/s to 1700 m/s) was lacking, this measurement was not
conclusive, and a viscous pill was further involved. After that,
three sets of data were available: data frac (processed using
HFPM), viscous pill depth determined by the pressure sharp increase
(standard viscous pill technology) and water hammer at the end of
the viscos pill (processed with HFPM technology). The results are
shown in Table 1.
[0082] It is observed that the use of a viscous pill only predicts
stages with the probabilities of 28 and 72% for the stages 3 and 4.
If the viscous pill pumping is the only technology used, the
operator cannot rely on this data. In a given case, the HFPM
technology was also applied and predicted 30 and 70% for the same
stages in the wellbore. Thus, their combination (combination of
probabilities from different kinds of measurements) is more
reliable. The main treatment stage gives one more piece of
information (water hammer at the end of pumping, which is processed
with HFPM); the results of three pumping operations are shown in
Table 2. It is worth noting that the water hammer data even in
combination with all the previous data is not conclusive for
identification of the dominant fluid-accepting stage: most likely
stage 4 is accepting the fluid (with a lower probability of
3.sup.rd stage). It may mean that both stages are accepting the
fluid simultaneously at different flowrates.
[0083] When the chemical (dissoluble) diverter (isolation agent) is
pumped, the produced water hammer date are analyzed and they show
that the previous stages (3 and 4) are isolated (Table 3). This
information is already enough to perform the second stimulation,
and as a result, viscous pill pumping is not performed at this
stage. However, the water hammer quality after diversion pumping is
in general poor. This is because during diversion pumping the most
fluid-accepting stages are isolated (blocked), and the tube wave
reflections may exist only from minor contributors (i.e., almost
closed fractures, which did not accept the fluid).
TABLE-US-00001 TABLE 1 Refract Monitoring results with the use of
HFPM and VP technologies. Two fluid injections are done (data frac
and viscous pill) Stimulated (fractured) stages OPERATION 1 2 3 4
DataFrac1 (HFPM 0% 11% 59% 30% processing) Viscous Pill 1 (HFPM 0%
0% 30% 70% processing) Viscous Pill 1 (VP) 0% 0% 28% 72%
TABLE-US-00002 TABLE 2 Refracturing Monitoring results with the use
of HFPM and VP technologies. Main job (fracturing) is added.
Stimulated (fractured) stages OPERATION 1 2 3 4 DataFrac1 (HFPM 0%
11% 59% 30% processing) DataFrac1 (HFPM processing) 0% 0% 30% 70%
Viscous Pill 1 (HFPM 0% 0% 28% 72% processing) Main frac job 1
(HFPM 0% 0% 42% 58% processing)
TABLE-US-00003 TABLE 3 Refracturing Monitoring results after
pumping a chemical (dissoluble) diverter. Stimulated (fractured)
stages OPERATION 1 2 3 4 DataFrac1 (HFPM processing) 0% 11% 59% 30%
DataFrac1 (HFPM processing) 0% 0% 30% 70% Viscous Pill 1 (VP) 0% 0%
28% 72% Main frac job 1 (HFPM 0% 0% 42% 58% processing) Diverter
pumping (HFPM 71% 24% 4% 0% processing)
[0084] Next, the second main treatment stage may be pumped. The
results are shown in Table 4 below. In such a stage, the viscous
pill is pumped. Table 5 presents the results for this pumping
stage. However, the viscous pill may not be performed due to the
combined use of VP and HFPM technologies in the previous stage
stimulation. The results seen in Table 5 are identical with the
results obtained without the second viscous pill pumping. This may
allow saving time and resources and may allow for starting the oil
production at a specific well faster. In this case, two major
treatment stages were analyzed. If there are more than two
consecutive stimulation treatments, evaluation of time and
resources needed may to be taken into consideration.
[0085] The results may be represented as shown in FIGS. 5 and 6.
Referring now to FIGS. 5 and 6, FIGS. 5 and 6 represent the depth
of fluid entry point for all events. The cloud size determines the
depth uncertainty; more than one cloud per event shows probability
of different stages stimulation. As seen for example in FIG. 5, the
clouds are located at the calculated depths, their sizes indicate
depth's uncertainties (in this figure only the final results are
shown). It is easy to see the stimulation depth change over the
whole treatment: the data frac, first viscous pill pumping, and
major treatment stage (job 1) show the stimulation with the stages
3 and 4. The diverter analysis showed that most likely the stages 3
and 4 are plugged and there is a reflection from the stages 1;
further measurements fully confirm that.
TABLE-US-00004 TABLE 4 Refrac Monitoring results without a second
viscous pill. Stimulated (fractured) stages OPERATION 1 2 3 4
DataFrac1 (HFPM processing) 0% 11% 59% 30% Viscous Pill 1 (HFPM
processing) 0% 0% 30% 70% Viscous Pill 1 (VP) 0% 0% 28% 72% Main
frac job 1 (HFPM 0% 0% 42% 58% processing) Diverter pumping (HFPM
71% 24% 4% 0% processing) Main frac job 2 (HFPM 100% 0% 0% 0%
processing)
TABLE-US-00005 TABLE 5 Refrac Monitoring results with the second
viscous pill. Stimulated (fractured) stages OPERATION 1 2 3 4
DataFrac1 (HFPM processing) 0% 11% 59% 30% Viscous Pill 1 (HFPM
processing) 0% 0% 30% 70% Viscous Pill 1 (VP) 0% 0% 28% 72% Main
frac job 1 (HFPM processing) 0% 0% 42% 58% Diverter pumping (HFPM
71% 24% 4% 0% processing) Viscous Pill 2 (HFPM processing) 100% 0%
0% 0% Viscous Pill 2 (VP) 100% 0% 0% 0% Main frac job 2 (HFPM
processing) 100% 0% 0% 0%
[0086] Advantageously, embodiments of the present disclosure
provide refracturing monitoring methods that allow determining the
effectiveness of refracturing a subterranean formation.
Specifically, it was found that such methods may allow
determination of the depth of a stage accepting fluids based on the
pressure response of a viscous pill combined with high frequency
pressure monitoring. The method provides features such as pressure
wave velocity calibration, insurance in fluid entry point,
measurement of depths of stimulated stages and avoidance of
overstimulating already stimulated stages. The method as described
herein may be applied for any fracture sizes, as well as any
distance between fractures. In addition, the refracturing
effectiveness monitoring method as described herein may provide on
the fly calibration of pressure wave velocity.
[0087] Although only a few example embodiments have been described
in detail above, those skilled in the art will readily appreciate
that many modifications are possible in the example embodiments
without materially departing from this invention. Accordingly, all
such modifications are intended to be included within the scope of
this disclosure as defined in the following claims. In the claims,
means-plus-function clauses are intended to cover the structures
described herein as performing the recited function and not only
structural equivalents, but also equivalent structures. Thus,
although a nail and a screw may not be structural equivalents in
that a nail employs a cylindrical surface to secure wooden parts
together, whereas a screw employs a helical surface, in the
environment of fastening wooden parts, a nail and a screw may be
equivalent structures. It is the express intention of the applicant
not to invoke 35 U.S.C. .sctn. 112, paragraph 6 for any limitations
of any of the claims herein, except for those in which the claim
expressly uses the words `means for` together with an associated
function.
* * * * *
References