U.S. patent application number 13/828055 was filed with the patent office on 2013-09-19 for wellbore real-time monitoring and analysis of fracture contribution.
This patent application is currently assigned to WEATHERFORD/LAMB, INC.. The applicant listed for this patent is WEATHERFORD/LAMB, INC.. Invention is credited to Rajan N. Chokshi, Luis E. Gonzales.
Application Number | 20130245953 13/828055 |
Document ID | / |
Family ID | 48049763 |
Filed Date | 2013-09-19 |
United States Patent
Application |
20130245953 |
Kind Code |
A1 |
Gonzales; Luis E. ; et
al. |
September 19, 2013 |
WELLBORE REAL-TIME MONITORING AND ANALYSIS OF FRACTURE
CONTRIBUTION
Abstract
Methods and apparatus are provided for calculating production of
each of a plurality of fractured intervals (or fractures) and
monitoring changes in the fracture contribution with time. Such
real-time monitoring and analysis may be performed by combining
temperature distribution (and pressure) measurements, a real-time
surface multiphase flow measurement, and an inflow model for each
fractured interval (or fracture). In this manner, the industry may
be able to understand the behavior of fractures and, in turn,
optimize the number of stages (i.e., fractured intervals), the
number of fractures, and the spacing between fractures and
stages.
Inventors: |
Gonzales; Luis E.; (Houston,
TX) ; Chokshi; Rajan N.; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
WEATHERFORD/LAMB, INC. |
Houston |
TX |
US |
|
|
Assignee: |
WEATHERFORD/LAMB, INC.
Houston
TX
|
Family ID: |
48049763 |
Appl. No.: |
13/828055 |
Filed: |
March 14, 2013 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
61611924 |
Mar 16, 2012 |
|
|
|
Current U.S.
Class: |
702/13 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 49/00 20130101; E21B 47/103 20200501 |
Class at
Publication: |
702/13 |
International
Class: |
E21B 49/00 20060101
E21B049/00 |
Claims
1. A method for determining production of hydrocarbons, comprising:
determining a temperature distribution associated with a plurality
of fractured intervals or fractures disposed along a well;
measuring a total flow rate for the well; modeling an inflow rate
for each of the plurality of fractured intervals or fractures; and
allocating production of each of the plurality of fractured
intervals or fractures based on the temperature distribution, the
total flow rate, and the inflow rates.
2. The method of claim 1, further comprising repeating the
determining, the measuring, and the modeling within a period short
enough to observe transient behavior of the plurality of fractured
intervals or fractures.
3. The method of claim 1, further comprising determining one or
more pressure measurements for the well, wherein allocating the
production is further based on the pressure measurements.
4. The method of claim 1, wherein determining the temperature
distribution comprises performing at least one of distributed
temperature sensing (DTS) or array temperature sensing (ATS).
5. The method of claim 1, wherein the measuring comprises measuring
the total flow rate using a multiphase flowmeter.
6. The method of claim 1, wherein at least one of the determining,
the measuring, or the modeling is performed daily.
7. The method of claim 1, wherein at least one of the determining,
the measuring, or the modeling is performed continuously.
8. The method of claim 1, wherein allocating the production
comprises: determining a first temperature value at a first time
for each of the plurality of fractured intervals or fractures;
determining a second temperature value at a second time for each of
the plurality of fractured intervals or fractures; calculating a
delta temperature value for the second time for each of the
plurality of fractured intervals or fractures by determining a
difference between the first and second temperature values for each
of the plurality of fractured intervals or fractures; calculating a
first ratio of the delta temperature value for the second time for
each of the plurality of fractured intervals or fractures to a
geothermal temperature; comparing the first ratio for the second
time to a maximum value of the first ratio over all previous times
for each of the plurality of fractured intervals or fractures; for
each of the plurality of fractured intervals or fractures,
designating the first ratio for the second time as the maximum
value of the first ratio over all previous times if the first ratio
for the second time is greater than a previously designated maximum
value; for each of the plurality of fractured intervals or
fractures, calculating a second ratio of the first ratio for the
second time to a currently designated maximum value of the first
ratio over all previous times; multiplying the second ratio for the
second time with the modeled inflow rate corresponding to the
second time for each of the plurality of fractured intervals or
fractures; summing results of the multiplication for each of the
plurality of fractured intervals or fractures; and determining an
allocation factor by dividing the measured total flow rate
corresponding to the second time by the sum.
9. The method of claim 8, wherein the first time occurs before the
hydrocarbons are produced.
10. The method of claim 8, further comprising applying the
allocation factor to the modeled inflow rate for each of the
plurality of fractured intervals or fractures.
11. The method of claim 1, wherein the total flow rate comprises a
total gas flow rate and wherein the inflow rates comprise inflow
gas rates.
12. The method of claim 1, wherein the plurality of fractured
intervals or fractures is located in a shale reservoir.
13. A system for determining production of hydrocarbons,
comprising: a temperature sensing device configured to determine a
temperature distribution associated with a plurality of fractured
intervals or fractures disposed along a well; a flowmeter
configured to measure a total flow rate for the well; and a
processing unit configured to: model an inflow rate for each of the
plurality of fractured intervals or fractures; and allocate
production of each of the plurality of fractured intervals or
fractures based on the temperature distribution, the total flow
rate, and the inflow rates.
14. The system of claim 13, wherein the plurality of fractured
intervals or fractures is located in a shale reservoir.
15. The system of claim 13, further comprising a pressure sensor
configured to determine one or more pressure measurements for the
well, wherein the processing unit is configured to allocate the
production further based on the pressure measurements.
16. The system of claim 13, wherein the processing unit is
configured to allocate the production by: determining a first
temperature value at a first time for each of the plurality of
fractured intervals or fractures; determining a second temperature
value at a second time for each of the plurality of fractured
intervals or fractures; calculating a delta temperature value for
the second time for each of the plurality of fractured intervals or
fractures by determining a difference between the first and second
temperature values for each of the plurality of fractured intervals
or fractures; calculating a first ratio of the delta temperature
value for the second time for each of the plurality of fractured
intervals or fractures to a geothermal temperature; comparing the
first ratio for the second time to a maximum value of the first
ratio over all previous times for each of the plurality of
fractured intervals or fractures; for each of the plurality of
fractured intervals or fractures, designating the first ratio for
the second time as the maximum value of the first ratio over all
previous times if the first ratio for the second time is greater
than a previously designated maximum value; for each of the
plurality of fractured intervals or fractures, calculating a second
ratio of the first ratio for the second time to a currently
designated maximum value of the first ratio over all previous
times; multiplying the second ratio for the second time with the
modeled inflow rate corresponding to the second time for each of
the plurality of fractured intervals or fractures; summing results
of the multiplication for each of the plurality of fractured
intervals or fractures; and determining an allocation factor by
dividing the measured total flow rate corresponding to the second
time by the sum.
17. The system of claim 16, wherein the processing unit is further
configured to apply the allocation factor to the modeled inflow
rate for each of the plurality of fractured intervals or
fractures.
18. The system of claim 13, wherein the temperature sensing device
comprises a distributed temperature sensing (DTS) device or an
array temperature sensing (ATS) device.
19. The system of claim 13, wherein the total flow rate comprises a
total gas flow rate and wherein the inflow rates comprise inflow
gas rates.
20. A system for determining production of hydrocarbons,
comprising: means for determining a temperature distribution
associated with a plurality of fractured intervals or fractures
disposed along a well; means for measuring a total flow rate for
the well; means for modeling an inflow rate for each of the
plurality of fractured intervals or fractures; and means for
allocating production of each of the plurality of fractured
intervals or fractures based on the temperature distribution, the
total flow rate, and the inflow rates.
Description
CLAIM OF PRIORITY UNDER 35 U.S.C. .sctn.119
[0001] The present application claims benefit of U.S. Provisional
Patent Application No. 61/611,924, filed Mar. 16, 2012, which is
herein incorporated by reference in its entirety.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] Embodiments of the present invention generally relate to
hydrocarbon production and, more particularly, to determining the
individual contribution of fractured intervals (or fractures) in
time.
[0004] 2. Description of the Related Art
[0005] Various tools may be used in order to measure the
contribution of the fractures within wellbores. Different services
companies may run production logging tools, and chemical tracers
may also be used to determine the fracture contribution. However,
these measurements may only provide a snapshot of what is happening
at the moment the measurements are performed, and may change with
time because conditions within the wellbore are transient.
SUMMARY OF THE INVENTION
[0006] Embodiments of the invention generally relate to allocating
production of each of a plurality of fractured intervals (or
fractures). This allocation may be performed by combining
temperature distribution (and pressure) measurements, a real-time
surface multiphase flow measurement, and an inflow model for each
fractured interval (or fracture).
[0007] One embodiment of the invention is a method for determining
production of hydrocarbons. The method generally includes
determining a temperature distribution associated with a plurality
of fractured intervals or fractures disposed along a well;
measuring a total flow rate for the well; modeling an inflow rate
for each of the plurality of fractured intervals or fractures; and
allocating production of each of the plurality of fractured
intervals or fractures based on the temperature distribution, the
total flow rate, and the inflow rates.
[0008] Another embodiment of the invention provides a system for
determining production of hydrocarbons. The system generally
includes a temperature sensing device configured to determine a
temperature distribution associated with a plurality of fractured
intervals or fractures disposed along a well, a flowmeter
configured to measure a total flow rate for the well, and a
processing unit. The processing unit is typically configured to
model an inflow rate for each of the plurality of fractured
intervals or fractures and to allocate production of each of the
plurality of fractured intervals or fractures based on the
temperature distribution, the total flow rate, and the inflow
rates.
[0009] Yet another embodiment of the invention provides a system
for determining production hydrocarbons. The system generally
includes means for determining a temperature distribution
associated with a plurality of fractured intervals or fractures
disposed along a well; means for measuring a total flow rate for
the well; means for modeling an inflow rate for each of the
plurality of fractured intervals or fractures; and means for
allocating production of each of the plurality of fractured
intervals or fractures based on the temperature distribution, the
total flow rate, and the inflow rates.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] So that the manner in which the above recited features of
the present invention can be understood in detail, a more
particular description of the invention, briefly summarized above,
may be had by reference to embodiments, some of which are
illustrated in the appended drawings. It is to be noted, however,
that the appended drawings illustrate only typical embodiments of
this invention and are therefore not to be considered limiting of
its scope, for the invention may admit to other equally effective
embodiments.
[0011] FIG. 1 is a conceptual diagram of a system for producing
hydrocarbons, the system having a pipe inside a casing and downhole
tools positioned at various locations along the pipe, in accordance
with an embodiment of the invention.
[0012] FIG. 2 illustrates an ideal reservoir model with multiple
fractures, in accordance with an embodiment of the invention.
[0013] FIG. 3 illustrates hydrocarbon production allocation from
multiple wells, in accordance with an embodiment of the
invention.
[0014] FIG. 4 illustrates hydrocarbon production allocation from a
horizontal well with multiple fractured intervals, in accordance
with an embodiment of the invention.
[0015] FIG. 5 is a flow diagram of example operations for
allocating hydrocarbon production to multiple fractured intervals
(or fractures), in accordance with an embodiment of the
invention.
[0016] FIG. 6 illustrates a workflow for identifying and
calculating the contribution of each fractured interval (or
fracture), in accordance with an embodiment of the invention.
[0017] FIG. 7 illustrates an example plot of gas production versus
number of contributing fractures, in accordance with an embodiment
of the invention.
DETAILED DESCRIPTION
[0018] Embodiments of the invention provide techniques and
apparatus for calculating production of each of a plurality of
fractured intervals (or fractures) and monitoring changes in the
fracture contribution with time. Such real-time monitoring and
analysis may be based on a combination of different measurements in
the wellbore, on the surface, and from a mathematical model, as
described below. In this manner, the industry may be able to
understand the behavior of fractures and, in turn, optimize the
number of stages (i.e., fractured intervals), the number of
fractures, and the spacing between fractures and stages.
[0019] Referring to FIG. 1, there is shown a hydrocarbon production
system 100 containing one or more production pipes 102 (also known
as production tubing) that may extend downward through a casing 104
to one or more hydrocarbon sources 106 (e.g., reservoirs). An
annulus 108 may exist between the pipe 102 and the casing 104. Each
production pipe 102 may include one or more lateral sections (e.g.,
created by horizontal drilling) that branch off to access different
hydrocarbon sources 106 or different areas of the same hydrocarbon
source 106. The fluid mixture may flow from sources 106 to the well
completion through the production pipes 102, as indicated by fluid
flow 130. The production pipe 102 may include one or more tools 122
for performing various tasks (e.g., sensing parameters such as
pressure or temperature) in, on, or adjacent a pipe or other
conduit as the fluid mixtures flow through the production pipes
102. The tools 122 may be any type of downhole device, such as a
flow control device (e.g., a valve), a sensor (e.g., a pressure,
temperature or fluid flow sensor) or other instrument, an actuator
(e.g., a solenoid), a data storage device (e.g., a programmable
memory), a communication device (e.g., a transmitter or a
receiver), etc.
[0020] Each tool 122 may be incorporated into an existing section
of production pipe 102 or may be incorporated into a specific pipe
section that is inserted in line with the production pipe 102. The
distributed scheme of tools 122 shown in FIG. 1 may permit an
operator of the system 100 to determine, for example, the level of
depletion of the hydrocarbon reservoir. This information may permit
the operator to monitor and intelligently control production of the
hydrocarbon reservoir.
[0021] Advances in directional drilling (e.g., horizontal drilling
as shown in FIG. 1) and reservoir stimulation techniques have
dramatically increased gas production from wells drilled in shale
reservoirs that were considered uneconomical not too long ago. In
spite of many advances in understanding the behavior of the
production of this type of reservoir, many unknowns remain, such as
determining the optimal length of horizontal sections, how many
stages, and determining how many fractures are optimal.
Particularly, it is difficult to predict productivity from cores,
logs, drillstem tests (DSTs), or early well-production performance.
Drainage volumes are uncertain, and well spacing is based on trial
and error methods.
[0022] The use of microseismic and production logs has helped in
the fracture evaluation to determine the drainage volume and
fracture inflow. Microseismic can provide useful information on the
development of fracture symmetry, half-length, azimuth, width and
height, and their dependence on the treatment parameters and
reservoir characteristics. Additionally, these fracture geometries
in conjunction with other measured or calculated parameters (e.g.,
rates, inflow models, etc.) can be used to better understand
fracture modeling and production characteristics.
[0023] Review of production logs have indicated that only a
percentage of the fractures are contributing to the production, and
until now, only snapshots of the fracture contributions have been
made. However, considering that this is a transient system (where
fracture contributions typically change with time, typically for
the first 15 to 20 months of production), a snapshot measurement is
not sufficient to understand the behavior of the fractures and
their contribution over time.
[0024] Accordingly, what is needed are techniques and apparatus for
establishing which fractures (or at least which fractured
intervals) are contributing and how much.
[0025] Due to the transient behavior, an ideal system would offer
continuous, permanent, and real-time monitoring on key variables
like production rates, pressure and temperature in an effort to
determine the fracture contributions. Procedures that integrate
different types of measurements and calculations in "real time" may
help to find and understand the behavior of the fractures and to
optimize the number of stages, fractures, and spacing.
[0026] Embodiments of the invention provide methods and apparatus
to optimize, or at least increase, the production of horizontal
fractured wells in shale reservoirs, for example. By integrating
different types of real-time measurements, methods described herein
enable the optimization of the number of fractures, the spacing of
fractures, and the length of the horizontal section by determining
the contribution of the fracture stages (or the fractures) over
time.
[0027] One way to solve this problem might be the installation of
downhole flowmeters in each fracture stage. However, this can be a
challenge operationally and may also be very costly and risky.
[0028] Instead, considering the very low permeability of shale
reservoirs (on the order of nanodarcys), it can be established that
a reservoir is created only after fracturing. If the spacing
between fractures is correct (such that the fractures do not
interfere with one another), the production allocation of each
fracture stage (or fracture) may be calculated in an analogous way
to that performed in a traditional field, where the total
production rates are allocated to each production well using well
testing measurements, done periodically with daily measurement
information like wellhead pressure. In this particular case, by
combining permanent downhole measurement of temperature (and one or
more pressure measurements at the heel and the toe of the wellbore,
for example), permanent wellhead flow measurement of the different
phases, and a mathematical transient model of the production rates
of each fracture, an acceptable production allocation can be made
as a function of time. Because the system is transient, such
allocation may be performed on a real-time basis.
[0029] In scenarios where the number of fractures is large, the
idealized system 200 shown in FIG. 2 may be used to model the
reservoir. In FIG. 2, multiple fractures 204, 206 are represented
as spaced along and transverse to the horizontal well trajectory
202. Assuming fracturing conditions were the same, the length and
width of each fracture in the fracture stage may be considered
equal. These parallel fractures are formed in an area (e.g., a
shale reservoir) with essentially zero permeability (as illustrated
in the region 212 unshaded in FIG. 2), thereby forming a region 214
of modified permeability (shaded in FIG. 2), essentially creating a
reservoir where none existed before. Although any number of
fractures (N.sub.Nfrac) may be formed with any spacing
therebetween, five fractures are illustrated in the fracture stage
of FIG. 2 (two external fractures 204 and three internal fractures
206) with equal fracture spacing. The fracture stage is defined by
confining external boundaries 210. FIG. 2 shows that external
fractures 204 are confined by virtual no-flow boundaries 208, which
force the external fractures to have the same behavior as the
internal fractures 206, and pure linear flow initially occurs. In
shale gas reservoirs of nanodarcy permeability, pure linear flow
opposite the fracture faces occurs for very long times.
[0030] The concept of Stimulated Reservoir Volume (SRV) is based on
the premise that negligible flow occurs from beyond the fracture
tips. The reservoir is created by the fracturing, and the reservoir
size is limited by the length of the main fracture. Production
performance from the fractured reservoir may be based on the SRV,
the fracture spacing, and the fracture conductivity.
[0031] The near-wellbore temperature distribution yielded by
distributed temperature sensing (DTS) or multi-point or array
temperature sensing (ATS) may be used to determine the relative
amount of fluid that each perforation interval contributes. If this
information is combined with one or more pressure measurements and
a real-time surface multiphase flow measurement in conjunction with
an inflow model for each fractured interval, a production
allocation may be calculated for each fracture. This approach is
analogous to a traditional well allocation where a daily aggregated
measurement at the production plant is back-allocated to each well
based on wellhead measurements like pressure, temperature, and well
performance. The description below provides details on the use of
these technologies to analyze the fracture behavior in horizontal
wells in shale reservoirs, for example.
[0032] FIG. 3 illustrates a multi-well system 300 in an oil/gas
production field, in which hydrocarbon production may be allocated
to each of the wells. In this allocation process, periodical (e.g.,
15 days to weeks or months) production well tests are performed on
each individual well, and daily (or in some cases, every few hours)
pressure (P) and/or temperature (T) measurements at or near the
wellhead 302 of each well are registered. The produced fluids from
each well may be collected at a manifold and then separated by a
separator 310 into oil, gas, and water. Daily (or in some cases,
every few hours or minutes) total flow rates of oil (Qo), gas (Qg),
and water (Qw) may be measured. With the production well tests,
using nodal analysis techniques, the well performance (P vs. Q
relation) for each well at the wellhead 302 is calculated. The use
of this wellhead performance with frequent wellhead pressure
measurements allows the flow rates of each individual well to be
determined.
[0033] Ideally, the addition of all these individual well flow
rates is the total production of the field, but for various reasons
(e.g., well performance of each well can change over time), there
is a difference between these values. To eliminate this difference,
an allocation factor (K) is found using the relationship between
the total flow rate (Qt) measured and the sum of the individual
well flow rates (.SIGMA.Qi) and may be subsequently used.
[0034] FIG. 4 illustrates a system 400 for allocating hydrocarbon
produced from a horizontal well with multiple fractured intervals
402 along a horizontal well, in accordance with an embodiment of
the invention. Although seven fractured intervals 402, each with
five fractures 404, are shown in FIG. 4, any number of fractured
intervals and any number of fractures per interval may be used. The
system 400 also includes a multiphase real-time flowmeter 406 and a
DTS cable 408 disposed downhole. The system may also include one or
more sensors 410 for measuring pressure (P) and/or temperature (T),
which may be disposed anywhere in the wellbore, such as in the
vertical section as shown. The multiphase flowmeter 406 may be
installed at or adjacent the wellhead or within the wellbore and,
for some embodiments, may be an optical flowmeter (e.g., an optical
downhole flowmeter). The DTS cable 408 may be installed adjacent
the casing 104, as shown in FIG. 4.
[0035] Drawing an analogy to the multi-well system 300 of FIG. 3,
each stage (i.e., fractured interval 402) in FIG. 4 is akin to a
producing well. With the help of the variation of temperature and a
transient inflow model, it is possible to calculate the production
of each stage at any time. In fact, if the temperature variation is
high enough to distinguish between fractures 404, it may also be
possible to allocate the production of each particular
fracture.
[0036] The analogy between production allocation for individual
wells and stages (or fractures) is possible (i.e., each stage or
fracture may be considered as an individual contributor to
production) because, due to the low permeability of this type of
reservoir (as described above with respect to FIG. 2), the
communication between stages, and even between fractures, is
negligible. The main characteristics of the fractures (e.g., length
and width) may be considered equal in each stage, assuming
fracturing conditions were the same. The inflow rate of each
fracture will be computed by an analytical transient model and
combined with the change in temperature (as determined by the DTS
cable 408, for example) at each stage referenced to an initial
condition prior to fracturing. In conjunction with the total flow
rate (Qt) measured by the multiphase flowmeter 406, a production
allocation for each stage (Qsi) (or each fracture) will be
performed.
[0037] FIG. 5 is a flow diagram of example operations 500 for
determining the contribution to hydrocarbon production of each
fractured interval (or each fracture). The operations 500 may
begin, at 502, by determining a temperature distribution associated
with a plurality of fractured intervals or fractures disposed along
a well. The temperature distribution may be determined by
performing at least one of distributed temperature sensing (DTS) or
array temperature sensing (ATS). The plurality of fractured
intervals or fractures may be located in a shale reservoir, for
example.
[0038] At 504, a total flow rate of a fluid (or any combination of
fluids) produced by the well (i.e., the produced hydrocarbons) is
measured. The total flow rate may be a total gas flow rate or a
total oil flow rate, for example. For some embodiments, the total
flow rate may be measured using a flowmeter disposed at the
surface. For example, the flowmeter may be disposed at or adjacent
a wellhead of the well.
[0039] An inflow rate is modeled at 506 for each of the plurality
of fractured intervals or fractures. The inflow rate may be an
inflow gas rate or an inflow oil rate, for example.
[0040] At 508, production of each of the plurality of fractured
intervals or fractures is allocated based on the temperature
distribution, the total flow rate, and the inflow rates. For some
embodiments, allocating the production at 508 may include: (1)
determining a first temperature value T.sub.0 at a first time
t.sub.0 (e.g., before production starts) for each of the plurality
of fractured intervals or fractures; (2) determining a second
temperature value T.sub.n at a second time t.sub.n (e.g.,
subsequent to the first time t.sub.0) for each of the plurality of
fractured intervals or fractures; (3) calculating a delta
temperature value (.DELTA.T.sub.n=T.sub.n-T.sub.0) for the second
time t.sub.n for each of the plurality of fractured intervals or
fractures by determining a difference between the first and second
temperature values for each of the plurality of fractured intervals
or fractures; (4) calculating a first ratio (.DELTA.T/Tg).sub.n of
the delta temperature value .DELTA.T.sub.n for the second time
t.sub.n for each of the plurality of fractured intervals or
fractures to a geothermal temperature (Tg) at the second time
t.sub.n (5) comparing the first ratio (.DELTA.T/Tg).sub.n for the
second time t.sub.n to a maximum value of the first ratio over all
previous times for each of the plurality of fractured intervals or
fractures (6) for each of the plurality of fractured intervals or
fractures, designating the first ratio for the second time t.sub.n
as the maximum value of the first ratio over all previous times if
the first ratio for the second time t.sub.n is greater than the
previously designated maximum value (7) calculating a second ratio
(.DELTA.T/Tg)/(.DELTA.T/Tg)max of the first ratio for the second
time t.sub.n for each of the plurality of fractured intervals or
fractures to the currently designated maximum value of the first
ratio over all previous times for each of the plurality of
fractured intervals or fractures; (8) multiplying the second ratio
for the second time t.sub.n with the modeled inflow rate
corresponding to the second time t.sub.n for each of the plurality
of fractured intervals or fractures; (9) summing results of the
multiplication for each of the plurality of fractured intervals or
fractures; (10) determining an allocation factor (K) by dividing
the measured total flow rate corresponding to the second time
t.sub.n by the sum; (11) applying the allocation factor (K) to the
modeled inflow rate for each of the plurality of fractured
intervals or fractures.
[0041] For some embodiments, the operations 500 may also include
repeating the determining at 502, the measuring at 504, and the
modeling at 506 within a period short enough to observe transient
behavior of the plurality of fractured intervals or fractures. The
determining, measuring, and/or modeling described above may be
performed and repeated with any desired frequency (at any desired
rate or periodicity). For example, the determining, measuring,
and/or modeling may be performed continuously, hourly, daily,
weekly, or with other frequencies.
[0042] For some embodiments, the operations 500 may also include
determining one or more pressure measurements for the well. In this
case, allocation of the production at 508 may also be based on the
pressure measurements. The pressure measurements may be made by one
or more pressure sensors located downhole, along the horizontal or
vertical portion of the wellbore. The pressure sensors may be
optical-based pressure sensors having one or more fiber Bragg
gratings (FBGs) located therein.
[0043] FIG. 6 illustrates a workflow 600 for identifying and
calculating the contribution of each fractured interval (or
fracture), in accordance with an embodiment of the invention. For
simplicity, the description below will focus on production
allocation for each fractured interval. The workflow 600 can be
easily expanded to production allocation for each fracture, as long
as the temperature variation is high enough to distinguish between
fractures.
[0044] In the workflow 600, the DTS (or ATS) data 602 is related to
the geothermal gradient value for each stage 402. The cable 408 may
be sampled with some periodicity to generate the data 602, leading
to temperature measurements at certain sampling times (t.sub.n).
For each sampling time (t.sub.n), the delta temperature (.DELTA.T)
between the temperature at the sampling time and at time t.sub.0 is
calculated for each stage 402. At 604, the .DELTA.T values for each
stage are divided by Tg to normalize the data. For some
embodiments, pressure measurements (e.g., taken by the sensors 410)
may be used to ensure accuracy of the .DELTA.T values for each
stage (e.g., by correlation with the temperature measurements). At
606, a ratio ((.DELTA.T/Tg)/(.DELTA.T/Tg)max) for the sampling time
(t.sub.n) is calculated for each stage 402. The ratio for each
stage is calculated by dividing the Tg-normalized .DELTA.T value
for this particular stage by the maximum Tg-normalized .DELTA.T
value over all previous times for this stage.
[0045] The .DELTA.T value at time t.sub.0 is initially assumed to
be the maximum Tg-normalized .DELTA.T value, so the ratio in this
case will be 1. The maximum .DELTA.T value is stored for later
validation of this assumption.
[0046] At 608, inflow transient models are run to generate inflow
rates for each stage 402 (indexed by "i"). The workflow 600 of FIG.
6 generates inflow gas rates for each stage (Qgfi), but inflow oil
rates or both may also be used. The inflow transient models either
produce the inflow rates at the sampling time (t.sub.n) as shown at
610, or interpolation or other techniques are used to determine
inflow rates at the sampling time based on inflow rates produced
for other times. At 612, the ratio at the sampling time (t.sub.n)
for each stage calculated at 606 is multiplied with the modeled
inflow rate for each stage from 610 corresponding to the sampling
time.
[0047] As described above, surface multiphase measurements may be
made at 614, for example, by the flowmeter 406, to generate one or
more total flow rates (Qg, Qo, and/or Qw) for the well. The total
flow rates may either be generated at the sampling time (t.sub.n)
as shown at 616, or interpolation or other techniques may be used
to determine the total flow rates at sampling time based on
measurements taken at other times.
[0048] The results of the multiplications at 612 for each of the
stages 402 at the sampling time (t.sub.n) may be summed
(.SIGMA.Q'gfi). At 618, this sum may be compared to the total gas
flow rate (Qg) corresponding to the sampling time (t.sub.n).
[0049] At the first sampling time (t.sub.0), the ratio for each
stage 402 calculated at 606 is multiplied by the Qgfi at t.sub.0
for each stage at 612, and the sum of all Qgfi values is compared
to the Qg corresponding to t.sub.0 at 618. For this time t.sub.0,
it is being assumed that all fractures are contributing at their
100% capacities, unless the .DELTA.T value is zero, in the case of
no contribution. For the next time t.sub.1, the value of
.DELTA.T.sub.1 will be compared to the value of .DELTA.T.sub.0. If
.DELTA.T.sub.1 is bigger, then a new maximum value is obtained.
This new maximum value replaces the previous value, and in this
case the contribution of this particular stage will be 100% during
this period of time, and the assumption on the previous time step
was wrong. A new calculation for t.sub.0 will be performed to
correct the first assumption and similarly at any time that a new
maximum value is found.
[0050] The workflow 600, operating on a "real-time" basis, will
increase well productivity, helping to determine what is the
optimal choke size to flow back the well and to have all fractures
contributing (or to find out which fractures do not contribute at
all). After this procedure is performed on different wells with a
different number of stages and/or fractures, a normalized graph of
production versus a number of contributing stages and/or fractures
can be obtained and, based on these results, an optimal number of
stages and/or fractures may be determined. A good relationship is
expected of production versus number of contributing fractures,
more consistent than the plot 700 of gas production versus number
of contributing fractures shown in FIG. 7 (from Modeland N. et al.,
"Stimulation's Influence on Production in the Haynesville Shale: A
Playwide Examination of Fracture-Treatment Variables that Show
Effect on Production," SPE 148940 presented at Canadian
Unconventional Resources Conference, 15-17 November 2011, Alberta,
Canada).
[0051] As described above, the near-wellbore temperature
distribution yielded by distributed temperature sensing (DTS) or
multi-point or array temperature sensing (ATS) may be used to
determine the relative amount of fluid that each perforation
interval contributes. If this information is combined with a
real-time surface multiphase flow measurement in conjunction with
an inflow model for each fractured interval (and one or more
pressure measurements), a production allocation may be calculated
for each fractured interval or fracture. This approach is analogous
to a traditional well allocation where a daily aggregated
measurement at the production plant is back-allocated to each well
based on wellhead measurements like pressure, temperature, and well
performance.
[0052] While the foregoing is directed to embodiments of the
present invention, other and further embodiments of the invention
may be devised without departing from the basic scope thereof, and
the scope thereof is determined by the claims that follow.
* * * * *