Note: Descriptions are shown in the official language in which they were submitted.
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WELLBORE REAL-TIME MONITORING AND
ANALYSIS OF FRACTURE CONTRIBUTION
BACKGROUND OF THE INVENTION
Field of the Invention
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.
Description of the Related Art
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
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).
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.
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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.
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
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.
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.
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FIG. 2 illustrates an ideal reservoir model with multiple fractures, in
accordance with an embodiment of the invention.
FIG. 3 illustrates hydrocarbon production allocation from multiple wells, in
accordance with an embodiment of the invention.
FIG. 4 illustrates hydrocarbon production allocation from a horizontal well
with
multiple fractured intervals, in accordance with an embodiment of the
invention.
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.
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.
FIG. 7 illustrates an example plot of gas production versus number of
contributing fractures, in accordance with an embodiment of the invention.
DETAILED DESCRIPTION
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.
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
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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.
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.
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.
The use of microseismic and production logs has helped in the fracture
evaluation to determine the drainage volume and fracture inflow. Microseismic
can
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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.
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.
Accordingly, what is needed are techniques and apparatus for establishing
which fractures (or at least which fractured intervals) are contributing and
how much.
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.
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.
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.
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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.
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 (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.
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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.
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.
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.
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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 (IQi) and may be
subsequently used.
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.
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.
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
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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.
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.
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.
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.
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 To at a first time to (e.g., before
production
starts) for each of the plurality of fractured intervals or fractures; (2)
determining a
second temperature value Tn at a second time tn (e.g., subsequent to the first
time to)
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for each of the plurality of fractured intervals or fractures; (3) calculating
a delta
temperature value (ATn = Tn - To) for the second time tn 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 (AT/Tg)n of the delta temperature value ATn for
the second
time tn for each of the plurality of fractured intervals or fractures to a
geothermal
temperature (Tg) at the second time tn (5) comparing the first ratio (AT/Tg),,
for the
second time tn 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 tn as
the
maximum value of the first ratio over all previous times if the first ratio
for the second
time tn is greater than the previously designated maximum value (7)
calculating a
second ratio (AT/Tg)/(AT/Tg)max of the first ratio for the second time tõ 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
tn with the
modeled inflow rate corresponding to the second time tn 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
tn by
the sum; (11) applying the allocation factor (K) to the modeled inflow rate
for each of
the plurality of fractured intervals or fractures.
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.
CA 02808858 2013-03-11
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.
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.
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 (tn). For each sampling time (tn), the delta temperature (AT)
between
the temperature at the sampling time and at time to is calculated for each
stage 402.
At 604, the AT 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 AT values for each stage (e.g., by
correlation with
the temperature measurements). At 606, a ratio ((ATTTg)/(AT/Tg)max) for the
sampling time (tn) is calculated for each stage 402. The ratio for each stage
is
calculated by dividing the Tg-normalized AT value for this particular stage by
the
maximum Tg-normalized AT value over all previous times for this stage.
The AT value at time to is initially assumed to be the maximum Tg-normalized
AT value, so the ratio in this case will be 1. The maximum AT value is stored
for later
validation of this assumption.
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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 (tn) 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 (tn) for each stage calculated at 606 is multiplied with the modeled
inflow rate for
each stage from 610 corresponding to the sampling time.
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 (tn) 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.
The results of the multiplications at 612 for each of the stages 402 at the
sampling time (tr,) may be summed (ZQ'gfi). At 618, this sum may be compared
to
the total gas flow rate (Qg) corresponding to the sampling time (tn).
At the first sampling time (to), the ratio for each stage 402 calculated at
606 is
multiplied by the Qgfi at to for each stage at 612, and the sum of all Qgfi
values is
compared to the Qg corresponding to to at 618. For this time to, it is being
assumed
that all fractures are contributing at their 100% capacities, unless the AT
value is
zero, in the case of no contribution. For the next time tl, the value of AT,
will be
compared to the value of AT . If ATi 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 to will
be
performed to correct the first assumption and similarly at any time that a new
maximum value is found.
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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. etal., "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).
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.
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.
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