Note: Descriptions are shown in the official language in which they were submitted.
1
ENHANCING HYDROCARBON RECOVERY OR WATER DISPOSAL IN MULTI-WELL
CONFIGURATIONS USING DOWNHOLE REAL-TIME FLOW MODULATION
TECHNICAL FIELD
The technical field generally relates to hydrocarbon recovery from
subterranean reservoirs and
water disposal into subterranean reservoirs, and more particularly to methods
and systems for
real-time fluid flow monitoring and control during hydrocarbon recovery and
water disposal.
BACKGROUND
When multiple vertical or horizontal injection and production wells are used
to recover oil from a
reservoir, breakthrough events can occur when fluid bypasses oil in the
reservoir and flows
directly from an injection well to a production well. Breakthrough events can
lead to low oil
recovery and high injection fluid to oil ratios. In such an event, it is
desirable to identify injection
wells and/or zones that may be responsible for the breakthrough, and then
reduce flow to those
wells and/or zones as well as re-allocate flow to other wells and zones.
Similarly, in other
applications, such as water disposal applications, it can be desirable to
decrease flow to
breakthrough zones and increase flow to non-breakthrough zones.
There are some known methods for well control including the use of downhole
flow reduction
valves. However, there are various challenges associated with known methods,
such as the
challenge of identifying and selecting one or more wells and/or zones for flow
control during
breakthrough events in a multi-well system.
Furthermore, when well components such as valves, fracturing ports and inflow
control
assemblies are arranged as part of a well tubular structure downhole, it can
be particularly
challenging to modulate, in real time, flow of a fluid from a borehole into a
well tubular structure
and/or from the well tubular structure into the borehole.
The following references relate to the general technical field: US 6736213, CA
2450223, WO
1997037102, US 20110146975, WO 2015110486, CA 2866274, US 20040244989, US
20120241148, US 2008/0262736, US 20120160484, US 20090188665, US 20030051873,
US
6853921, and US 7448447. These documents are incorporated herein by reference
as are all
other documents mentioned herein.
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There is a need for solutions and technologies that overcome as least some
challenges of known
methods.
SUMMARY
The present invention generally relates to controlling flow in subterranean
wells in response to a
breakthrough event in a production well or into a low permeability region of
the reservoir. Many
different methods and systems can be used in the context of such flow control
to enhance
hydrocarbon recovery or water disposal, for example.
The present invention relates to a reservoir flow control system and method
that selectively
regulates surface and/or downhole flows in multiple injection and production
wells, which may be
vertical or horizontal, in order to enhance the recovery operation.
Performance improvements can
include maximizing oil recovery and minimizing water production from the
reservoir, for example.
Novel control methods can be used to regulate surface and downhole flows in
multiple wells and
in multiple zones of the reservoir, simultaneously and in real-time, by
selecting the well and zone
in which to control flow during a fluid breakthrough event to increase
recovery. The control
methods can use sources of data including but not limited to: inter-well
distance, well log data,
well physical dimensions, well and reservoir physical property data, reservoir
permeability and
porosity data, historical injection and production rates from multiple wells
and reservoir zones,
distributed sensor data, reservoir flow rates inferred from distributed sensor
data. The invention
can also be applied to control methods that are used to favor flow of disposal
fluids into a reservoir,
by reducing flow via wells and/or zones into thief or "breakthrough" regions
of the reservoir in
order to increase water/fluid disposal efficiency in reservoirs or other
applications. The invention
can also be applied to control methods that are used to favor flow of injected
fluids into a reservoir,
by favoring flow via wells and/or zones into low permeability regions of the
reservoir for certain
applications where fluid injection into low permeability regions of the
reservoir is to be
encouraged. The invention further includes a method for inference of
subsurface zonal flow rates
based on downhole sensor data in a well. The invention also includes a
downhole flow control
assembly for controlling flow from a borehole into a well tubular structure
and/or from the well
tubular structure into the borehole. Furthermore, the present invention
includes installation and
operation of the downhole flow control assembly in multiple wells, in
conjunction with the above
control methods to control the flow in the appropriate well and reservoir zone
in order to increase
oil recovery.
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BRIEF DESCRIPTION OF THE DRAWINGS
Fig 1 is a schematic diagram of multiple wells and a control system. In
particular, it shows an
example of a control system for controlling flows in multiple wells and zones
simultaneously. The
controller receives data and signals from multiple wells and other sources
simultaneously and in
real-time. During a breakthrough event in one or more production wells and/or
zones, the
controller selects specific wells and/or zones for which to apply flow control
using one or more
methods. The controller then sends flow control signals to downhole flow
control assemblies
and/or surface equipment to control flow to multiple wells and/or zones
simultaneously.
Fig 2 is a side view of an injector-producer well pair. In particular, it
shows an example of fluid
injection in a horizontal or deviated well arrangement. The injection and
production wellbores are
drilled vertically until a geologic hydrocarbon bearing layer is reached. Each
well is then turned
horizontal and the horizontal section of the well is used to inject or produce
into the surrounding
rock. The horizontal section of the well is divided into several zones,
represented by arrows in the
dashed box. Each zone may be of different length and have no limit on their
length. The wellbore
in each zone may be perforated i.e. holes are created to allow injection and
production of fluids.
During the recovery of oil with very high viscosities, typically greater than
100 centipoise, steam
or solvent is injected into the production zones via the horizontal injection
well to reduce the
viscosity of the oil in those zones. The lower viscosity oil and fluids then
flow into the production
well and to the surface for processing. The figure above represents the fluid
flow distribution
expected in an ideal condition ¨ all flows are equally distributed to maximize
oil recovery in all
zones.
Fig 3 is a side view of an injector-producer well pair showing a breakthrough.
In particular, it shows
an example of breakthrough occurring in a horizontal or deviated well
arrangement. Fluids are
injected into the hydrocarbon bearing zones via perforations in the injection
well, in order to
produce hydrocarbons in those zones. During the recovery of oil with very high
viscosities,
typically greater than 100 centipoise, steam or solvent is injected in order
to reduce the viscosity
of the oil in those zones, allowing oil flow and production. However, due to
various factors
including reservoir rock property heterogeneity, the injected fluids
preferentially flow into a small
number of zones directly to the production well, leading to bypassed
hydrocarbon zones.
Bypassed zones can lead to poor hydrocarbon recovery and higher produced fluid-
oil ratio.
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Fig 4 is a top plan view schematic of a well layout. In particular, it shows
an example of a well
layout in which multiple well flow control can be employed. Plan view showing
the locations of an
injection well and four surrounding production wells. Each injection well
(injector) has an index i.
Each production well (producer) has an index k.
Fig 5 is a perspective view of a well payout. In particular, it shows a three-
dimensional view of the
layout shown in
Fig 4 is a top plan view schematic of a well layout. In particular, it shows
showing the locations
and zones of one injection well and four surrounding production wells. Each
injection well
(injector) has an index i and each zone in an injection well has index j. Each
production well
(producer) has an index k and each zone in a production well has index m.
Fig 6 is a top plan view of another well layout. In particular, it shows a
well layout in which multiple
well flow control can be employed. Plan view showing the locations of two
injection wells and four
surrounding production wells. Each injection well (injector) has an index i.
Each production well
(producer) has an index k.
Fig 7 is a perspective view of the well layout. In particular, it shows a
three-dimensional view of
the layout shown in Fig 6 showing the locations and zones of two injection
wells and four
surrounding production wells. Each injection well (injector) has an index i
and each zone in an
injection well has index j. Each production well (producer) has an index k and
each zone in a
production well has index m.
Fig 8 is a graph of cumulative oil recovery versus time. In particular, it
shows cumulative recovery
for the cases of no flow control versus flow control, for the example shown in
Figs 4 and 5. The
recovery improvement with the flow control method is approximately 37%.
Fig 9 is another graph of cumulative oil recovery versus time. In particular,
it shows cumulative
recovery for the cases of no flow control versus flow control, for the example
shown in Figs 6 and
7. The recovery improvement with the flow control method is approximately 41%.
Fig 10 is a block diagram of an inference method. In particular, it shows an
example of inference
method based on downhole temperature sensing, where the inference model
adjusts zonal flow
rates until the temperature profile from the field matches the temperature
profile calculated using
a physical model of the wellbore and reservoir. The inference is carried for
one or more timesteps
in order to build an inferred zonal flow rate history for the wellbore.
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Fig 11 is a cross-sectional view of an example flow control assembly provided
in a downhole
tubing. In particular, it illustrates a cross section of an example downhole
flow control assembly
that can control flow in specific well zones. The device is connected to the
tubing string. The
device houses one or more actuators, which can be hydraulic, solenoid or
another type. Each
actuator controls flow to a specific flow port by opening or closing that
port, using a
spring/stem/plug system or another system. To allow actuation, each actuator
has an electric or
pneumatic or other supply connection, which allows actuation of each actuator
individually.
Communication to each actuator from a controller or control systems can be
achieved in several
ways, including electrically, pneumatically, from the surface, from downhole,
wired, wireless.
Fig 12 is a cross-sectional view of an example flow control assembly provided
in a downhole
tubing. It shows an example of how a downhole flow control assembly regulates
flow. In the above
example, one of the flow ports is closed and the other three ports are open.
This allows partial
flow of fluid between the tubing string and the flow ports. By having one or
more actuators and
controlling each actuator individually, a variable number of flow ports can be
opened or closed or
partially open, allowing for variable flow control with the device.
Fig 13 is a side plan view of a tubing string with flow control assemblies. It
shows an example of
two flow control assemblies that are placed on a tubing string. One is
annotated "Flow Control
Device A" and the other annotated "Flow Control Device B". The controllers are
separated from
one another and the above/below flow zones by packers, limiting their flow
into their respective
zones, A and B. Each of the flow control valve apparatus could contain any
number of control
valves greater than one, depending on the application.
DETAILED DESCRIPTION
Methods and systems for enhancing in situ hydrocarbon recovery operations that
use multiple
injector or producer wells having independently adjustable flow assemblies can
include
automated detection of breakthrough events in production segments or zones,
determination of
corresponding injection segments of the injector having over-connectivity with
the production
segment and being responsible for the breakthrough, and then adjusting zonal
fluid flows within
the hydrocarbon-containing reservoir and the wells. Adjusting the zonal fluid
flows can include
reducing inflow set points for the production segment experiencing
breakthrough, increasing
inflow set points in other production segments, reducing outflow set points
for the injection
segment identified as having over-connectivity with the production segment,
and increasing
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outflow set points of at least one other fluid outflow assembly in the
injector. An automated control
system can be implemented to simultaneously and in real time monitor a multi-
well operation to
adjust fluid inflow and outflows in different segments of the producer and
injector wells in order to
increase hydrocarbon recovery, increase hydrocarbon production rates, decrease
injection fluid
losses, or generally enhance the hydrocarbon recovery process.
In the following description and the associated figures, a number of potential
embodiments and
aspects of the methods and systems will be described.
Systems and methods to modulate and control surface and subterranean fluid
flow to increase oil
recovery or enhanced recovery efficiency for multiple vertical or horizontal
wells is described
below. The techniques described herein can facilitate fluid flow control
simultaneously and in real-
time. An example of a control system is shown in Fig 1.
In one embodiment, the system can generally operate as follows:
(1) Breakthrough of fluid (e.g. brine, water, gas, steam, etc.) is detected in
one or more
producers and/or production zones.
(2) To control breakthrough, a multi-well control method selects one or more
injection and/or
production zones to shut off or control.
(3) A controller or control system receives, stores and transmits flow control
signals and other
data for multiple wells simultaneously, preferably in order to increase oil
recovery or
enhance other aspects of the recovery process.
(4) A downhole flow profile inference system that takes in distributed sensor
measurements
in real-time and calculates the flow rates of fluid into the
injection/production zones.
(5) A downhole flow control system including, in one or more injection and/or
production wells,
allocates and controls flow to specific wells and zones to minimize or inhibit
breakthrough.
Inflow and outflow assemblies can be provided along producer and injector
wells,
respectively, and the assemblies can be controlled to reduce flow causing and
proximate
to the breakthrough and to increase flow at locations more distant from the
breakthrough.
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(6) A surface flow control system, including but not limited to pumps and flow
control valves,
allocates and controls flow to multiple wells simultaneously to minimize or
inhibit
breakthrough.
Additional details regarding the above steps and general operation of the
system are provided
below:
(1) Breakthrough detection
In a reservoir containing multiple vertical or horizontal injection wells and
multiple vertical or
horizontal production wells, breakthrough can occur where fluid injected from
an injection well into
the reservoir bypasses oil and other barriers and flows directly, or "breaks
through", into the
production well. Injection fluid breakthrough can result in a notable increase
in fluid-to-
hydrocarbon ratio. While small amounts of injected fluid can become part of
the production fluid
during normal operations, breakthrough results in a more sudden increase and
higher quantities
of injection fluid in the production fluid. Breakthrough can also cause
challenges in terms of the
overall injection strategy, down hole pressures, and short-circuiting. The
injected fluid can be one
of many types of secondary recovery fluids such as brine, water, gases that
can be miscible or
immiscible with oil, as well as gases that are condensable (e.g. steam or
certain organic solvents),
or a combination of such fluids. Breakthroughs can be detected in several
ways. For example,
breakthroughs can be detected by analyzing the changes in the ratio of
injection fluid to
hydrocarbons in production wells over time (e.g. water-to-oil ratios (WOR) for
water flooding
applications), such that a sudden increase in WOR indicates a breakthrough,
where WOR
gradient and maximum WOR thresholds can be pre-determined and integrated into
the detection
system. Breakthroughs can also be detected by analyzing the changes in
subsurface flow rates
over time, if available. For example, a sudden increase in the inflow rate can
indicate a
breakthrough event. Breakthroughs can also be detected by analyzing well
temperatures,
particularly in the case where the injected fluid has a relatively high
temperature compared to the
hydrocarbons (e.g. steam) or relatively low temperature compared to the
hydrocarbons. For
instance, when steam is injected into a reservoir and the temperature at a
location along the
producer well becomes notably hotter compared to the typical temperature of
the production fluid,
this can indicate that steam or hot condensate breakthrough has occurred at
that location.
It is possible to use multiple breakthrough detection methods in combination.
For example, by
monitoring temperature, inflow rates, and fluid-to-hydrocarbon ratios along
production wells, the
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data can be used for a more reliable determination of breakthrough events and
their locations. In
addition, depending on the nature and cause of the breakthrough, different
detection methods
may hold more weight. For example, in a steam injection process, detection of
temperatures in
the vicinity of the steam temperature can be a reliable indicator to determine
that steam
breakthrough has occurred and that it is a relatively direct breakthrough.
However, even if the
temperature at the producer does not increase significantly, a sudden increase
in the WOR of the
production fluid can indicate a breakthrough as well, e.g., where the steam
has condensed and
cooled while passing through a circuitous channel in the reservoir.
It is also possible for multiple breakthrough events to occur in a given well
and/or in more than
one well and reservoir zone simultaneously. For example, in a water flooding
application, two
producers could each experience a breakthrough event which may originate from
two different
water injectors, from the same water injector at different injection locations
along the well, or from
the same water injector at one location along the well.
When the hydrocarbon recovery application involves injection of fluids via a
horizontal injector
well and recovery of oil is performed via a nearby horizontal producer well,
uniform distribution of
injected fluids is desirable to achieve desirable oil recovery (see Fig 2).
For example, when steam
or solvent is injected via a horizontal wellbore to enter the reservoir and
reduce the viscosity of
hydrocarbons to facilitate production, the injected steam or solvent can
channel through
heterogeneous rock regions that may be near or adjacent the wellbore and cause
poor distribution
of the injected fluid along the injector well (see Fig 3). Such poor
distribution of injected fluid can
lead to premature breakthrough in the nearby producer well, leading to
bypassed hydrocarbons,
poor conformance, low recovery, and high produced fluid-to-oil ratios. For
horizontal injector-
producer well pairs that require a start-up phase, the methods and systems
described herein can
be used to enhance start-up. Methods and systems for detecting breakthrough of
fluid in multiple
horizontal injector and producer wells and associated zones can be implemented
in the same way
as for vertical injectors and producers.
Breakthrough detection can also involve monitoring along injector wells to
identify segments of
the wells with higher outflow rates indicative of channeling from the
injection portions to the
production ports of the producer wells. If breakthrough is detected along a
producer well (e.g.
based on one or more of the above-described methods) and increased outflow is
detected at a
particular injection segment within a close timeframe, it can be inferred that
that high outflow
injection segment is fluidly linked with the breakthrough event. If the
injector and producer
CA 2985953 2017-11-17
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locations are relatively close together, such as well segments that are a
similar depth or
longitudinal position along the well, this can be an additional indicator that
the two locations are
fluidly linked and are behind the breakthrough. Identifying this causal link
between injector and
producer segments can facilitate subsequent control strategies.
(2) Multi-well control method
Once breakthrough has occurred in a particular zone between an injector and a
producer well, it
becomes inefficient to continue injecting the fluid into that zone. By
redirecting flow to more
productive zones, oil recovery and process performance can be enhanced.
In one embodiment, a control strategy may be applied wherein the fluid
injected via a particular
injection well and into particular zone of that well is either shut off or
reduced when breakthrough
occurs in a specific production well and particular zone of that well. The
injection fluid flow can
then be redirected to production wells and reservoir zones that are not
experiencing breakthrough.
Also, production well zones that are experiencing breakthrough can also have
their flow shut off
or reduced, with fluid flow reallocated to other production zones.
In an embodiment, the control method determines which injection and/or
production well and
which reservoir zones are responsible for the breakthrough, in order to
control flow in and to those
zones and re-allocate flow to other zones.
Flow reallocation can be done in multiple ways, with the algorithm selecting
the way. For example,
the algorithm could facilitate the reallocation in one or more of the
following:
- Keep rate constant in the well and allow flow to re-allocate naturally,
based on the physical
characteristics (e.g. permeability) of each non-breakthrough zone.
- Re-allocate flow to the non-breakthrough injection and/or production
zones proportionally
to the magnitude of the zonal flow rate. For example, if a non-breakthrough
zone has low
flow rate, increase its flow rate.
- Re-allocate flow to injection zones that have high connectivity to high-
productivity zones.
In such a case, first identify production zones that are not experiencing
breakthrough and
have high productivity, i.e., high flow rate and/or low water-oil ratio. Then,
identify injection
layers that have high connectivity to those high-productivity zones. Increase
the flow to
those injection layers.
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- Re-
allocate based on distance from breakthrough zone. Wells closer to the
breakthrough
zone have less re-allocation. For example, referring to Fig 1, if a given
producer has a
breakthrough at a given zone m, then m can be shut off and m+1 and m-1 can be
reduced
or shut off as well; if injector zone j is identified as the cause of the
breakthrough, then j
can be shut off, j+1 and j-1 can be reduced or maintained due to their
proximity to j, and
the remaining injection zones can receive the reallocated injection fluid.
One, two or more
zones around a breakthrough can be shut off, reduced or maintained depending
on
various factors.
There are several ways to determine which reservoir zone is responsible for or
contributing to a
breakthrough event, based on flow rates and/or "connectivity" between
injection and production
well zones. "Connectivity" (denoted as F) is defined as how easily flow from
one well zone can
reach another. If it is relatively easy for fluid to flow from one zone to
another, those zones can
be said to have high connectivity. In addition, the higher the connectivity
between an injector and
producer well and/or zones, the more likely that breakthrough in that producer
is caused by flow
from that injector or injection zone. In Fig 1, injection wells have index i,
injection zones have
indices (i, j), production wells have index k, and production zones have
indices (k, m). In this
context, connectivity can be defined as:
F(i, j, k, m) ¨ Connectivity between injection zone (i, j) and production zone
(k, m);
F(i, j, k) ¨ Connectivity between injection well zone (i, j) and production
well k;
F(i, k, m) ¨ Connectivity between injection well i and production zone (k, m);
and
F(i, k) ¨ Connectivity between injection well i and production well k.
The following methods can be used to determine which well zones are
responsible for
breakthrough events, based on the type of data and sensing available in the
field.
(a) Downhole sensing on injector and producer;
(b) Downhole sensing on injectors only;
(c) Downhole sensing on producers only;
(d) Flow rate and property histories with no downhole sensing;
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(e) No downhole sensing or flow rate and property histories.
The methods are described in more detail below.
(a) Downhole sensing on injectors and producers
This method can be used if downhole sensors that allow measurement or
inference of subsurface
flow in individual well zones are installed on both the injector and producer
wells. Downhole
sensing could be complemented with reservoir tracer test data, reservoir flow
survey data, or
other techniques that provide subsurface zonal rates. With these sensors
installed, injection and
production rate histories for each well zone, as well as histories for other
data such as temperature
and pressure, can be assembled in real-time. Connectivity F(i, j, k, m)
between each injection and
production zone can be established through use of capacitance-resistance (CRM)
models,
physical models of the reservoir, or other modelling techniques. When
breakthrough occurs in a
production zone (k, m), the control method can carry out a combination of the
following actions:
(i) Reduce flow set point for production zone (k, m);
(ii) Increase flow set point for production zones other than breakthrough zone
(k, m);
(iii) Reduce flow set points for injection zones responsible for the
breakthrough, based on:
= Higher connectivity F(i, j, k, m) between injection and production zone;
= Higher flow rate Qinj(i, j) in an injection zone;
= Higher rate of increase of flow rate (dQinj/dt)(i, j) in an injection
zone; and/or
= A combination of the above or similar metrics; for example, select zones
with higher
product F(i, j, k, m) Qinj(i, j) * (dQinj/dt)(i, j) for flow reduction.
(iv) Increase flow set points for injection zones not responsible for the
breakthrough, based
on:
= Lower connectivity F(i, j, k, m) between injection and production zone;
= Lower flow rate Qinj(i, j) in injection zone;
= Lower rate of increase of flow rate (dQinj/dt)(i, j) in injection zone;
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= A combination of above or similar metrics. For example, select zones with
lower
product F(i, j, k, m) * Qinj(i, j) * (dQinj/dt)(i, j) for flow increase.
In some cases, breakthrough can be considered to have a threshold based on
water-to-oil ratio
or other parameters (see CA2866274, for example). Also, a given zone can be
"partially"
responsible for breakthrough.
There can be a threshold for connectivity to determine whether an injector is
responsible or not
for breakthrough. The control can also be continuous, where all injection
zones are ranked by
their connectivity to the breakthrough zone and the control action is
proportional or related to the
connectivity and/or ranking. It can be that more than one injection zone is
responsible for
breakthrough. A combined threshold/continuous control scheme can be applied,
i.e. certain zones
are deemed responsible for breakthrough since their connectivity is above a
threshold, and the
control applied to these zones is proportional or related to their
connectivity.
The WO ratio, flow rate or other measured parameters can be used to determine
whether
breakthrough has occurred by comparing the measured value to a threshold
value. Rather than
a given property threshold (e.g. flow rate or WO ratio thresholds), the
determining factor that is
used can be a gradient, such as the rate of change of flow rate or WO ratio.
Thresholds and/or
gradients (flow, rate of change of flow rate, connectivity, etc.) can be used
to determine whether
breakthrough has occurred and to determine the selection and magnitude of flow
control applied.
For instance, either there is a sudden change in flow rate, or the flow rate
exceeding a certain
amount can be used. A sudden change in connectivity is also possible.
(b) Downhole sensing on injectors only
This method can be used if downhole sensors that allow measurement or
inference of subsurface
flow in individual well zones are installed on injector wells but not on some
or all producer wells.
Downhole sensing could be complemented with reservoir tracer test data,
reservoir flow survey
data, or other techniques that provide subsurface zonal rates. With these
sensors installed,
injection rate histories for each well zone, as well as histories for other
data such as temperature
and pressure, can be assembled in real-time. Connectivity F(i, j, k) between
each injection zone
and production well can be established through use of capacitance-resistance
(CRM) models, or
physical models of the reservoir. When breakthrough occurs in a production
well k, the control
method can carry out a combination of the following actions:
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(i) Reduce flow set point for production well k;
(ii) Increase flow set point for production wells other than breakthrough well
k, or convert the
production well into an injection well by pumping water into the well;
(iii) Reduce flow set points for injection zones responsible for the
breakthrough, based on:
= Higher connectivity F(i, j, k) between injection zone and production
well;
= Higher flow rate Qinj(i, j) in injection zone;
= Higher rate of increase of flow rate (dQinj/dt)(i, j) in injection zone;
= A combination of above or similar metrics. For example, select zones with
higher
product F(i, j, k) * Qinj(i, j) * (dQinj/dt)(i, j) for flow reduction.
(iv) Increase flow set points for injection zones that are not responsible for
the breakthrough,
based on:
= Lower connectivity F(i, j, k) between injection zone and production well;
= Lower flow rate Qinj(i, j) in injection zone;
= Lower rate of increase of flow rate (dQinj/dt)(i, j) in injection zone;
= A combination of the above or similar metrics. For example, select zones
with lower
product F(i, j, k) * Qinj(i, j) * (dQinj/dt)(i, j) for flow increase.
In this case, the whole producer well is throttled when breakthrough is
detected rather than a
particular zone/segment of the producer, and one increases the flow rates in
other producers
while shifting the injection per segment/zone of the responsible injector
well.
Another action could be taken is that when breakthrough is detected in a
producer, that well could
be converted from a producer to an injector by pumping a fluid (e.g. water)
into the well. This well-
conversion approach could be applied when the producer is positioned in a
region of the reservoir
that would benefit from additional fluid injection. This well conversion
technique can be used in
other methods described herein instead of shutting off a given production
well.
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In some embodiments, this method could be modified in the context of a fluid
disposal application,
where injection wells dispose fluid (e.g. water) into reservoirs, with no
production wells. In this
case, a breakthrough event can occur when the flow rate increases rapidly in a
particular injection
well and/or zone. For water disposal applications, the control method can be
adapted to carry out
the following actions:
(i) Detect breakthrough in an injector well or zone if the following condition
is true:
[dyma8(0-dyma20(i)] >= al AND y(i) > bl AND t(i) ¨ timelastbreakthough > cl
Here dyma8 and dyma20 are the moving averages of the rate of change of
well/zonal flow
rate with 8 and 20 day intervals; y is well/zonal flow rate;
timelastbreakthrough
corresponds to the time at which the last breakthrough is deemed to have
occurred; and
al, bl and cl refers to threshold that would be case specific for each well.
(ii) Decrease flow set points for injection wells and/or zones experiencing
breakthrough,
based on:
= The condition in action (i) being true;
= Higher flow rate Qinj(i) or Qinj(i, j) in injection well or zone,
respectively;
= Higher rate of increase of flow rate (dQinj/dt)(i) or (dQinj/dt)(i, j) in
injection well or
zone, respectively;
= A combination of above or similar metrics. For example, select zones with
higher
product Qinj(i, j) * (dQinj/dt)(i, j) for flow increase.
(iii) Increase flow set points for injection wells and/or zones that are not
experiencing
breakthrough, based on:
= The condition in action 1 being false;
= Lower flow rate Qinj(i) or Qinj(i, j) in injection well or zone,
respectively;
= Lower rate of increase of flow rate (dQinj/dt)(i) or (dQinj/dt)(i, j) in
injection well or
zone, respectively;
= A combination of above or similar metrics. For example, select zones with
lower
product Qinj(i, j) * (dQinj/dt)(i, j) for flow reduction.
CA 2985953 2017-11-17
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In various fluid injection applications without simultaneous joint operation
of production wells, it
may be desirable to minimize or avoid fluid travelling into low permeability
zones. In such cases,
the above control method can be adapted to reduce or shut off injection via an
injector well zone
that has high connectivity with a low permeability zone.
In some embodiments where certain fluids are injected into a reservoir, the
method could
optionally be used with no production wells and the injection into low
permeability regions of the
reservoir could be favored. In some other applications, the fluid injection
can be focused on
injection into low permeability regions and/or maximizing fluid flow into the
reservoir in general,
and in such cases breakthrough events can be treated as favorable (e.g.
injected fluid finds a low
permeability zone and thus starts flowing more easily into that zone). In such
applications, the
control method can be adapted to carry out the following actions:
(i) Detect breakthrough in an injector well or zone if the following condition
is true:
[dyma8(i)-dyma20(i)] >= al AND y(i) > IA AND t(i) ¨ timelastbreakthough > cl
Here dyma8 and dyma20 are the moving averages of the rate of change of
well/zonal flow
rate with 8 and 20 day intervals; y is well/zonal flow rate;
timelastbreakthrough
corresponds to the time at which the last breakthrough is deemed to have
occurred; and
al, bl and cl refers to threshold that would be case specific for each well.
(ii) Increase flow set points for injection wells and/or zones experiencing
breakthrough, based
on:
= The condition in action (i) being true;
= Higher flow rate Qinj(i) or Qinj(i, j) in injection well or zone,
respectively;
= Higher rate of increase of flow rate (dQinj/dt)(i) or (dQinj/dt)(i, j) in
injection well or
zone, respectively;
= A combination of above or similar metrics. For example, select zones with
higher
product Qinj(i, j) * (dQinj/dt)(i, j) for flow increase.
(iii) Decrease flow set points for injection wells and/or zones that are not
experiencing
breakthrough, based on:
= The condition in action 1 being false;
CA 2985953 2017-11-17
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= Lower flow rate Qinj(i) or Qinj(i, j) in injection well or zone,
respectively;
= Lower rate of increase of flow rate (dQinj/dt)(i) or (dQinj/dt)(i, j) in
injection well or
zone, respectively;
= A combination of above or similar metrics. For example, select zones with
lower
product Qinj(i, j) * (dQinj/dt)(i, j) for flow reduction.
It is noted that depending on the particular well injection and/or production
process that is being
implemented, the control method can be adapted accordingly to target injection
into the regions
of the reservoir having the desired permeability or "breakthroughability"
properties.
(c) Downhole sensing on producers only
This method can be used if downhole sensors that allow measurement or
inference of subsurface
flow in individual well zones are installed on producer wells but not on some
or all injector wells.
Downhole sensing could be complemented with reservoir tracer test data,
reservoir flow survey
data, or other techniques that provide subsurface zonal rates. With these
sensors installed,
production rate histories for each well zone, as well as histories for other
data such as temperature
and pressure, can be assembled in real-time. Connectivity F(i, k, m) between
each injection well
and production zone can be established through use of capacitance-resistance
(CRM) models,
or physical models of the reservoir. When breakthrough occurs in a production
zone (k, m), the
control method carries out a combination of the following actions:
(i) Reduce flow set point for production zone (k, m);
(ii) Increase flow set point for production zones other than breakthrough zone
(k, m);
(iii) Reduce flow set points for injection wells responsible for the
breakthrough, based on:
= Higher connectivity F(i, k, m) between injection well and production
zone;
= Higher flow rate Qinj(i) in injection well;
= Higher rate of increase of flow rate (dQinj/dt)(i) in injection well;
= A combination of above or similar metrics. For example, select wells with
higher
product F(i, k, m) * Qinj(i) * (dQinj/dt)(i) for flow reduction.
CA 2985953 2017-11-17
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(iv) Increase flow set points for injection wells that are not responsible for
the breakthrough,
based on:
= Lower connectivity F(i, k, m) between injection well and production zone;
= Lower flow rate Qinj(i) in injection well;
= Lower rate of increase of flow rate (dQinj/dt)(i) in injection zone;
= A combination of the above or similar metrics. For example, select wells
with lower
product F(i, k, m) * Qinj(i) * (dQinj/dt)(i) for flow increase.
Methods (a), (b), and (c) described above rely, at least in part, on inference
of subsurface zonal
rates from downhole sensor data, obtained from downhole temperature sensor,
downhole
acoustic sensors or other similar sensors. Various types and structures or
such sensors are
available. For example, optical fiber sensors are available for this purpose;
however, any form of
distributed wellbore sensing can be used for inference provided the physical
models relating flow
to sensor measurements are understood. An example of such an inference method
using
downhole temperature sensing is described below. It includes the following
steps:
1. First, the downhole temperature sensor data is gathered and processed to
obtain a
temperature profile along the wellbore, which is used as the main input for
inference.
2. A physical model of the wellbore and surrounding reservoir is built in
order to simulate the
behavior of the sensor in the wellbore. The model can be constructed using one
or more
of the following: a programming language (e.g. Python, FORTRAN, etc.), a
physics
simulator (e.g. Fluent or Star-CCM+ or Comsol), a pipeline simulator (e.g.
OLGA or
PIPESIM), a reservoir simulator (e.g. UTChem or Eclipse). It includes the
following parts:
a. Wellbore fluid properties, including density, specific heat capacity,
thermal
conductivity, viscosity, compressibility, thermal expansion coefficient,
latent heat
of vaporization.
b. Wellbore casing, tubing and cement dimensions and physical properties,
including
radius, depth, sensor location, perforation zone locations, density, specific
heat
capacity, thermal conductivity.
CA 2985953 2017-11-17
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c. Reservoir properties, including density, specific heat capacity, thermal
conductivity, geothermal gradient, surface temperature.
d. Surface injection historical data, such as flow rate and temperature
e. Heat and mass transfer differential equations, heat transfer correlations,
grid block
sizes in different geometric directions, simulation run time, number of time
steps.
3. An optimization method, an example of which is shown in Fig 10, infers
zonal rates from
field sensor data as follows:
a. Start at time = 0 and input model properties, initial temperature.
b. Increment time by one timestep.
c. Adjust or guess zonal rates.
d. Solving the differential equations of the physical model with the adjusted
rates to
obtain a simulated model sensor temperature profile.
e. Calculating the error between the model and field sensor temperature
profiles,
which could be residual sum of squares or another error formulation.
f. Repeating the three steps c, d, e above until the error between
simulated and field
sensor data is minimized.
g. Repeat from step b until maximum simulation time is reached.
The inference method, which is run for one or more timesteps, outputs zonal
flow rate histories
for the well, which can be monitored in real-time by operators, or used in
real-time control methods
described herein. If properties or model input data are unavailable, estimates
for the missing data
can be used for inference.
(d) Flow rate and property histories with no downhole sensing
This method can be used, for example, in cases where surface injection and
production histories
are known; no downhole sensors or techniques that allow measurement or
inference of
subsurface flow in individual well zones exist; histories for other properties
such as bottomhole
CA 2985953 2017-11-17
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pressure are known (optional). It should be noted that such data can be used
in addition to data
described for methods (a) to (c), to provide additional data confirmation.
In the event that no rate histories for individual well zones are available,
surface rate histories can
be used to establish connectivity between injection and production wells. Rate
histories can be
obtained by flow measurements at the surface, reservoir tracer test data,
reservoir flow survey
data, or another flow measurement technique. Connectivity F(i, k) is
established between each
injection well i and production well k through use of capacitance-resistance
(CRM) models, or
physical models of the reservoir. When breakthrough occurs in a production
well k, the control
method can carry out a combination of the following actions:
(i) Reduce flow set point for production well k;
(ii) Increase flow set point for production wells other than breakthrough well
k, or convert the
production well into an injection well by pumping water into the well;
(iii) Reduce flow set points for injection wells responsible for the
breakthrough, based on:
= Higher connectivity F(i, k) between injection well and production well;
= Higher flow rate Qinj(i) in injection well i;
= Higher rate of increase of flow rate (dQinj/dt)(i) in injection well i;
= A combination of above or similar metrics. For example, select wells with
higher
product F(i, k) * Qinj(i) * (dQinj/dt)(i) for flow reduction.
(iv) Increase flow set points for injection wells that are not responsible for
the breakthrough,
based on:
= Lower connectivity F(i, k) between injection well and production well;
= Lower flow rate Qinj(i) in injection well;
= Lower rate of increase of flow rate (dQinj/dt)(i) in injection zone;
= A combination of the above or similar metrics. For example, select wells
with lower
product F(i, k) * Qinj(i) * (dQinj/dt)(i) for flow increase.
CA 2985953 2017-11-17
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(e) No downhole sensing or flow rate and property histories
This method can be used, for example, in the event downhole sensing data for
flow inference,
flow rate histories, and property histories are unavailable. In this case,
connectivity can be
established based on the effective path length between an injector and the
producer between
injectors and producers. Effective path length can be given by the following
equation:
T oc ¨
K*
where T is the effective path length between injector and producer, L is the
path length between
injector and producer, and K* is the harmonic average permeability for the
path between the
injector and producer. Permeability can be obtained from well logs, core
samples, or other data.
Other variations for the effective path length equation are possible. For
example, different types
of average permeability and length measures can be used, and non-linear
relationships between
effective path length, permeability and path length are possible.
Also, T, L and K* can be between injection and production zones, between
injection and
production wells, injection zones and production wells, or injection wells and
production zones.
The example of this method described below uses effective path length between
injection zones
and production wells.
Permeability and path length data can be obtained from analysis of well survey
data, geologic
models, permeability obtained by correlations of well-log derived porosity or
other methods to
obtain zone flow properties from static geologic and geophysical data.
When breakthrough occurs in a production well k, the control method carries
out a combination
of the following actions:
(i) Reduce flow set point for production well k;
(ii) Increase flow set point for production wells other than breakthrough well
k, or convert the
production well into an injection well by pumping a fluid (e.g. water) into
the well;
(iii) Reduce flow set points for injection zones responsible for the
breakthrough, based on
shorter effective path length T(i, j, k) between injection zone and production
well;
CA 2985953 2017-11-17
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(iv) Increase flow set points for injection zones that are not responsible for
the breakthrough,
based on higher effective path length T(i, j, k) between injection zone and
production well,
or based on lower harmonic average permeability of the path between the
injection zone
and production well.
In case that all the injector zones may be shut off via this selection method,
the flow would be
effectively stopped to that particular injector. This method can be continued
until all injection wells
are shut off.
For example, this method can be applied to a simulated reservoir field in two
different well layouts,
in which injection zones are shut off based on shortest effective path length
and reallocated to
other zones proportional to harmonic average permeability (variations on Steps
iii and iv above).
Figs 4 and 5 show the layout for a field containing four producers and a
single injector ("five-
spot"), and Figs 6 and 7 show the layout for a field containing four producers
and two injectors. In
an example of the effectiveness of this "shut-off' method for multiple wells,
the method was
applied to these simulated fields, with each injector given an overall
injection rate of 2000 barrels
per day. In the single injector case, cumulative oil recovery was increased by
approximately 37%
through the use of the shut-off method, compared with cumulative recovery with
no control
method used. In the two-injector case, the shut-off method increased the
cumulative oil recovery
by approximately 41%. Fig 8 shows the recovery improvement for the single
injector example,
and Fig 9 shows the improvement for the two-injector example.
(3) Control system
The above-described selection methods are examples of methods that can be used
to decide
how to control flow for multiple injection and production wells and zones,
which can be done in a
real-time and simultaneous manner. A controller or control system (e.g. which
may be referred to
as a distributed control system) is used to achieve the appropriate control
actions. In general, the
control system can operate as follows:
1. Control system receives data regarding which injection wells and
zones need and/or would
benefit from flow control.
2. Control system sends signals to downhole and/or surface flow control
apparatuses to
either increase or decrease respective flow set points.
CA 2985953 2017-11-17
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3. Control system stores flow set points and standard control parameters, such
as
proportional, integral, derivative terms.
The data processing methods and associated data that are required for control
can either be
stored and executed within the control system's own structure or outside the
control system on a
server that may be remote from the actual control unit. The data processing
methods can include:
1. Inference algorithms to obtain subsurface flows from downhole sensor data.
Example
techniques for such algorithms can be adapted from CA2866274 and SPE paper
140442,
which describes inference for fracturing applications.
2. Selection methods to decide which well zones to apply flow control to. The
selection
methods are described in detail in the present document.
An example of the control system determining the occurrence of a breakthrough
event is
described in CA2866274. Regarding flow reallocation strategies performed by
the controller,
some options have been described above. Reallocation can be done depending on
the extent to
which the given zone is "connected" to the breakthrough zone. Reallocation can
be performed
according to a step-change or a gradual change. Either on/off control or PID
control can be used.
(4) Downhole flow control system and assemblies
The downhole flow control system receives signals from a controller or control
system, as
described above, and adjusts openings on downhole flow control assemblies to
control flow into
and/or out of the reservoir regarding one or more wells and/or well zones. The
downhole flow
adjustments can be done in substantially real-time. An example schematic of
the downhole flow
control system for a single well is shown in Fig 13. The flow control system
is installed on one or
more well tubing strings, and each well installation can include the following
components:
1. Downhole flow control assemblies, which can include multiple actuated
ports, that allow
fine control of flow rate to individual well zones. The device is described in
more detail
below with reference to Figs 11 and 12.
2. Packers that isolate the downhole flow control assemblies so that flow
through one device
is restricted to a particular reservoir zone.
CA 2985953 2017-11-17
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The configuration presented above is scalable both in terms of total
controllable reservoir wells
and zones and in the level, or fidelity, of control allowed by the number of
ports on each flow
control assembly. For instance, a given well can include one, two, three,
four, or more of the flow
control assemblies (examples of which are illustrated in Figs 11 and 12), and
each of the flow
control assemblies can include one, two, three, four, or more independent
adjustable flow ports
for adjusting the flow into or out of the string depending on implementation
in producer or injector
wells.
One example of a downhole flow control assembly used for flow control to
individual well zones
is shown in Fig 11. The flow control assembly can include a valve body which
houses various
parts and connects to the well tubing string. The flow control assembly can
also include one or
more actuator (e.g. solenoid, hydraulic, or other actuator) attached to the
valve body, one for each
flow port. The flow control assembly can also include one or more flow ports
through which fluid
flow can be controlled. The flow ports can be apertures through the wall of
the tubular body and
being in fluid communication with the reservoir to allow injection of fluids
into the reservoir or flow
of production fluids into the body and then up the string.
At least one of the flow parts can be adjusted so that to open area through
which the fluid flow
can pass is modified. In one example, at least one and preferably each flow
port is actuated by a
dedicated actuator which opens or closes (fully or partially) the flow port
via a plug system. The
plug system can include an end plug configured to fit into the corresponding
port, a stem attached
to the end plug, and a spring or other biased mechanism, for example, that can
force the end plug
into the port. The spring/stem/plug combination or another system that allows
opening, closing or
partial opening of flow ports by the actuator can therefore enable
modifications to the port
openings and thereby control the fluid flow through the ports.
As illustrated, it can be preferred that each flow port is actuated by a
dedicated actuator which
opens or closes the flow port via the spring/stem/plug. However, other example
flow control
assemblies can be envisioned where two or more ports can be opened or closed
using one
actuator and plug system (e.g. if there are two or more plug ends).
Preferably, each of the ports
can be independently operated in open and closed modes (optionally in a
partial open mode as
well), to enable the flow control assembly to enable incremental increases or
decreases of flow.
In some cases, each port is operable in an open or closed position, and enough
of the ports are
provided in each assembly to enable a desired maximum flow as well as several
reduced flow
settings that are provided by closing a certain number of ports independently.
CA 2985953 2017-11-17
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The flow control assembly can also include an electric and/or hydraulic supply
connection that
facilitates electric/hydraulic actuation to the actuators individually. The
corresponding connection
can be of several forms including from the surface, from a battery located
downhole, from a
pneumatic supply located downhole, etc. The connection can be provided to
allow for several
forms of communication between the actuator and a controller or control
system, including wired
or wireless communication.
In operation, fine control can be achieved by the downhole flow control
assembly based on the
number of ports that are opened and/or the degree to which they are opened. An
example of this
flow regulation is shown in Fig 12. In the example, one flow port is closed
and the other three flow
ports are opened. Assuming identical pressure drops and flow characteristics
for each port, the
device is allowing 75% of its capacity to flow through the valve. If more
ports are closed, the flow
capacity is reduced further, and if more ports are open, flow capacity
increases. By increasing the
number of ports and partially opening ports, fine flow control can be achieved
with the assembly.
The ports can be distributed in various ways around the tubular body of the
flow control assembly.
For example, the ports can be aligned along a longitudinal length of the body,
or can be distributed
evenly at different locations around the body. The ports can all be the same
size and general
configuration, or they can be of different sizes and/or structures. For
example, ports of different
sizes can facilitate certain control strategies by allowing small ports to be
adjusted to enable fine
flow control and larger port adjustments to enable rapid control of larger
flows. Various structures
can be used to enable the ports to open or close.
(5) Surface flow control system
The surface flow control system can include pumps and flow control valves that
regulate flow to
and from multiple injection and production wells. The surface flow control
system receives signals
from the controller or control system, and can adjust pump speeds and/or flow
control valve
openings that are part of the surface fluid transport system to control flow
in real-time to one or
more wells. Thus, in a breakthrough event, flow control can be applied
simultaneously at the
surface and downhole.
An example of surface and downhole flow control working together for a
specific well arrangement
is provided. If the system detects breakthrough in an injection zone, it would
shut off that zone
and increase flow to other injection zones. However, the system could increase
the flow to other
zones using a combination of opening downhole valves (which are downhole)
and/or increasing
CA 2985953 2017-11-17
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the injection pump speed (which is at surface). This could be useful to open a
downhole valve
completely and then increase the flow rate through that valve even further.
Having both surface
and downhole flow modulation capabilities can enhance flexibility and
performance of the overall
system.
There are numerous types of wells, reservoirs, recoverable hydrocarbons, and
injection fluids that
can be used with the methods and systems described herein. The wells can be
horizontal, vertical
or inclined. The wells can be multi-lateral wells with lateral well segments.
The wells can be drilled
using conventional or advanced drilling techniques, e.g., directional drilling
techniques for
providing non-linear wellbores. The wells can be completed in a number of ways
using various
components, tubing structures, liners, instrumentation, as well as inflow and
outflow assemblies.
The inflow and outflow assemblies can be mounted with respect to the
production or injection
strings or tubing in various ways, and can be arranged in regular or irregular
patterns in terms of
spacing, orientation, initial operating configuration, etc.
The wells can be provided in a number of different patterns, such as three-
spot, four-spot, five-
spot, seven-spot, nine-spot, inversed five-spot, inversed four-spot, inversed
seven-spot, inversed
nine-spot, direct line drive or staggered line drive, for example. When the
wells are horizontal,
they can be provided as vertically spaced well pairs, as per classic steam
assisted gravity
drainage (SAGD) well pairs. Multiple well pairs can be arranged in parallel to
each other or at
angles. Additional horizontal or vertical wells can be provided in the
vicinity of well pairs to provide
additional injection or production.
The wells can be part of a flooding operation where the injection fluid
displaces the hydrocarbons
by pressure drive and other mechanisms. The wells can be part of a gravity
drainage recovery
process, as used in SAGD. The wells can be part of other hydrocarbon recovery
processes, such
as in situ combustion, VAPEX, solvent assisted processes, and so on. The
injection fluids used
as part of the hydrocarbon recovery process can be selected based on the
nature of the reservoir
and the hydrocarbons targeted for recovery, and can include water, steam,
organic solvents, non-
condensable gases, and mixtures thereof. The hydrocarbons for recovery can
include gas, oil,
heavy oil, or bitumen. The hydrocarbon-containing reservoirs that are
exploited can also be pre-
treated in preparation for the hydrocarbon recovery process, for example by
performing hydraulic
fracturing, pre-heating, or other conditioning processes for preparing the
hydrocarbons or
reservoir matrix for the recovery process.
CA 2985953 2017-11-17
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The following are summaries of possible examples of the invention:
(A) A system for controlling surface and subsurface flows in real-time and in
multiple injection and
production wells, vertical and/or horizontal, to increase oil recovery and
reduce fluid-oil ratio,
an example of which is shown in Fig 1. The fluid injected can be water, water
with suitable
chemicals, brine, gas miscible with oil, gas immiscible with oil, condensable
gas, steam or any
combination thereof. The system can also be used to improve efficiency of
water disposal into
reservoirs. The system includes:
i. A method for selection and application of flow control to a specific
wells and/or zones
during a breakthrough event in one or more injection and/or production wells
and/or
zones. More than one zone and well can be selected for flow control.
ii. A controller or control system that receives, stores and transmits
signals and other
data for flow control for multiple wells simultaneously. Control data may be
received
from and sent to downhole and/or surface sources, including but not limited to
sensors,
flow control assemblies, process historians, pumps, water cut meters, manual
input.
iii. One or more downhole flow control systems in one or more injection
and/or production
wells that can allocate and control flow to specific wells and zones.
iv. One or more pieces of equipment that enable flow control at the
surface, including
pumps and flow control valves.
(B) A method for selection of a specific well and zone for flow control during
breakthrough based
on correlation of inferred subsurface zonal rate histories for multiple
injection and production
wells. Inferred subsurface rate histories can be obtained from real-time
interpretation of
distributed sensor data for multiple zones in multiple injection and
production wells, or from
test data such as reservoir tracer test data, reservoir flow survey data, or
another flow
measurement technique. The inferred injection and production rates for each
combination of
injection and production zones are correlated using statistical inference
models such as
Capacitance Resistance Models, physical models of the reservoir and wellbore,
or other
methods. The control action for the selected well zones depends on the
strength of the
correlation of inferred flow rate between those zones and the production wells
or zones in
which breakthrough is detected. Furthermore, the control action can involve
increasing flow
in production zones in which breakthrough does not occur.
CA 2985953 2017-11-17
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(C) A method for selection of a specific well and zone for flow control during
breakthrough based
on real-time interpretation of distributed sensor data from multiple injection
wells. Distributed
sensor data can be used to infer subsurface rate histories for multiple zones
in multiple
injection wells. Other subsurface flow measurement data, such as reservoir
tracer test data
and reservoir flow survey data can serve as substitutes for distributed sensor
measurements.
During a breakthrough event, the inferred subsurface rate histories from
multiple injection
zones are correlated with surface production rate histories for the
breakthrough wells using
statistical inference models such as Capacitance Resistance Models, physical
models of the
reservoir and wellbore, or other methods. The strength and direction of the
correlations is
used to select how much injection wells and zones should have flow reduced or
increased.
Furthermore, the control action involves increasing flow in production wells
in which
breakthrough does not occur.
(D) A method for selection of a specific well and zone for flow control that
favors breakthrough
events based on real-time interpretation of distributed sensor data from
multiple injection
wells. Distributed sensor data can be used to detect breakthroughs based on
flow rate
changes, as well as infer subsurface rate histories, for multiple zones in
multiple injection
wells. Other subsurface flow measurement data, such as reservoir tracer test
data and
reservoir flow survey data can serve as substitutes for distributed sensor
measurements. A
breakthrough event is first detected based on flow rate changes in injection
zones. When
breakthrough occurs in an injection well and zone, that zone is selected for
an increase in its
flow rate setpoint. Injection wells and zones that are not experiencing
breakthrough have their
flow rate setpoints reduced. The strength of the control action for each well
and zone depends
on the flow rate, rate of change of flow rate, or a combination thereof, for
that well and zone.
Breakthroughs can occur in multiple wells and zones simultaneously.
(E) A method for selection of a specific well and zone for flow control during
breakthrough based
on real-time interpretation of distributed sensor data from multiple
production wells.
Distributed sensor data can be used to infer subsurface rate histories for
multiple zones in
multiple production wells. Other subsurface flow measurement data, such as
reservoir tracer
test data and reservoir flow survey data can serve as substitutes for
distributed sensor
measurements. During a breakthrough event in specific production wells and/or
zones, the
inferred rate histories from the production wells and/or zones are used to
select how much
production wells and/or zones should have their flow increased or decreased.
Also, the
surface rate histories from multiple injection wells are correlated with
subsurface production
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rate histories for the breakthrough zones using statistical inference models
such as
Capacitance Resistance Models, physical models of the reservoir and wellbore,
or other
methods. The strength and direction of the correlations is used to select
which injection wells
should have flow reduced and which injection wells should have flow increased.
(F) A method for selection of specific wells for flow control during
breakthrough based on
correlation of surface injection and production rates in each well to
establish well connectivity.
The injection and production rates can be obtained by flow measurement at the
surface,
reservoir tracer test data, reservoir flow survey data, or another flow
measurement technique.
The injection and production rates can be correlated using statistical
inference models such
as Capacitance Resistance Models, physical models of the reservoir and
wellbore, or other
methods. The control action for the selected wells depends on the strength of
the flow
correlation between those wells and the production wells in which breakthrough
is detected.
Furthermore, the control action can involve increasing flow in wells in which
breakthrough
does not occur.
(G) A method for selection of a specific well and zone for flow control during
breakthrough based
on the permeability and path length between wells and/or zones to establish
well connectivity.
Permeability and path length data can be obtained from analysis of well survey
data, geologic
models, permeability obtained by correlations of well-log derived porosity or
another method
to obtain zone flow properties from static geologic and geophysical data. The
connectivity
between wells and/or zones can be established based on the permeability and/or
distance of
the path between those wells and/or zones. The flow control action for well
zones depends
on their connectivity with the production wells or zones in which breakthrough
is detected.
Furthermore, the control action can involve increasing flow in wells in which
breakthrough
does not occur.
(H) A method for selection of specific wells and/or zones for flow control
during breakthrough
based on a combination of the selection methods mentioned in the above
summaries (A), (B),
(C), (D), (E), (F) and/or (G).
(I) A downhole flow control system configurable to modulate flow in discrete
permeable,
subterranean reservoir zones. Fig 13 depicts two discrete reservoir zones
separated by
packers contained on a tubing string. In between each packer is a downhole
flow control
assembly. From the surface, the flow control assemblies can be commanded to
restrict flow
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into or out of either of the reservoir zones. The configuration presented
below is scalable both
in terms of total controllable reservoir zones and in the level, or fidelity,
of control allowed by
the number of ports on the flow control assembly.
(J) System for controlling flow into or out of the flow control assembly via a
variable number of
flow ports, an example of which is shown in Fig 11. The system includes:
i. A valve body which houses various components below and connects to the
well tubing
string
ii. One or more solenoid/hydraulic/other actuator attached to the valve
body.
iii. A spring/stem/plug combination or another system that allows opening,
closing or
partial opening of flow ports by the actuator.
iv. One or more flow ports through which fluid flow can be controlled. Each
flow port is
actuated by a dedicated actuator which opens or closes the flow port via the
spring/stem/plug. By controlling each of the ports individually, a high degree
of
sustained flow control downhole is allowed. An example of this actuation of
individual
flow ports to control flow is shown in Fig 12.
v. An electric/hydraulic supply connection that allows electric/hydraulic
actuation to each
actuator individually. The connection can be of several forms including from
the
surface, from a battery located downhole, from a pneumatic supply located
downhole.
The connection allows for several forms of communication between the actuator
and
a controller or control system, including wired or wireless communication.
(K) Method for inferring subsurface zonal injection rate histories zonal
injection flows for
waterflood, steam injection, or fluid injection in vertical or horizontal
wells based on
interpretation of downhole distributed sensor data. The method can be
performed in
real-time or on data gathered a priori. The method has the following steps:
i. Downhole distributed sensor data, obtained from distributed temperature
sensors,
distributed acoustic sensors, or similar sensors, is gathered and processed to
obtain
a sensor data profile along the wellbore
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ii. Wel!bore fluid properties, including density, specific heat capacity,
thermal
conductivity, viscosity, compressibility, thermal expansion coefficient,
latent heat of
vaporization, are stored
Wellbore casing, tubing and cement dimensions and physical properties,
including
radius, depth, sensor location, density, specific heat capacity, thermal
conductivity, are
stored
iv. Reservoir properties, including density, specific heat capacity,
thermal conductivity,
geothermal gradient, surface temperature, are stored
v. Surface injection historical data, such as flow rate and temperature, is
stored
vi. A physical model of the wellbore and surrounding reservoir is built using
the above
inputs. The model consists of heat and mass transfer differential equations,
heat
transfer correlations, grid block sizes in different geometric directions,
simulation run
time, number of time steps
vi. A calculation method analytically or numerically solves the equations
of the physical
model in step vi above using specific zonal rates as inputs, in order to
obtain simulated
sensor data (temperature, pressure, velocity, etc.) expected for those zonal
rates
vii. An optimization method infers zonal rates from field sensor data by
adjusting zonal
rates; solving the physical model as in step vii with the adjusted rates to
obtain
simulated sensor data; calculating an error between the simulated and field
sensor
data; repeating the prior adjusting, solving, error steps until the error
between
simulated and field sensor data is minimized.
The above method is carried out for one or more timesteps and outputs zonal
flow rate
histories for the well, which can be monitored by operators, or used in
control methods
described herein. If properties or model input data are unavailable, estimates
for the
missing data can.
(L) An automated method for controlling zonal fluid flow in a subsurface
hydrocarbon-containing
reservoir in which multiple wells are located, the multiple wells comprising:
a producer configured to recover hydrocarbons from the hydrocarbon-containing
reservoir and comprising a plurality of production segments along a length of
the
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producer respectively configured with independent adjustable fluid inflow
assemblies, the fluid inflow assemblies being operated at respective initial
inflow
set points; and
an injector configured to provide an injection fluid into the hydrocarbon-
containing
reservoir and comprising a plurality of injection segments along a length of
the
injector respectively configured with independent adjustable fluid outflow
assemblies, the fluid outflow assemblies being operated at respective initial
outflow
set points;
the method comprising:
detecting an injection fluid breakthrough event in a production segment of the
producer;
determining an injection segment of the injector having over-connectivity with
the
production segment of the producer experiencing the injection fluid
breakthrough
event;
adjusting fluid flow within the hydrocarbon-containing reservoir and the
wells, the
adjusting comprising:
reducing an inflow set point of the fluid inflow assembly located at the
production segment of the producer to reduce fluid inflow from the
hydrocarbon-containing reservoir;
increasing an inflow set point of at least one other fluid inflow assembly in
the producer;
reducing an outflow set point of the fluid outflow assembly located at the
injection segment identified as having over-connectivity with the production
segment; and
increasing an outflow set point of at least one other fluid outflow assembly
in the injector.
(M) An automated method for controlling fluid flow in a subsurface hydrocarbon-
containing
reservoir in which multiple wells are located, the multiple wells comprising:
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multiple producers each configured to recover hydrocarbons from the
hydrocarbon-containing reservoir; and
multiple injectors each configured to provide an injection fluid into the
hydrocarbon-
containing reservoir at respective initial outflow set points;
the method comprising:
detecting an injection fluid breakthrough event in a breakthrough producer;
determining an injector having over-connectivity with the breakthrough
producer
experiencing the injection fluid breakthrough event;
adjusting fluid flow within the hydrocarbon-containing reservoir and the
wells, the
adjusting comprising:
reducing an inflow set point of the breakthrough producer to reduce fluid
inflow from the hydrocarbon-containing reservoir;
increasing an inflow set point of at least one other producer;
reducing an outflow set point of the injector identified as having over-
connectivity with the breakthrough producer; and
increasing an outflow set point of at least one other injector.
(N) An automated method for controlling fluid flow in a subsurface hydrocarbon-
containing
reservoir in which multiple wells are located, the multiple wells comprising:
a producer configured to recover hydrocarbons from the hydrocarbon-containing
reservoir; and
multiple injectors each configured to provide an injection fluid into the
hydrocarbon-
containing reservoir at respective initial outflow set points;
the method comprising:
detecting an injection fluid breakthrough event in the producer;
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determining an injector having over-connectivity with the producer
experiencing
the injection fluid breakthrough event;
adjusting fluid flow within the hydrocarbon-containing reservoir and the
wells, the
adjusting comprising:
reducing an inflow set point of the breakthrough producer to reduce fluid
inflow from the hydrocarbon-containing reservoir;
reducing an outflow set point of the injector identified as having over-
connectivity with the producer; and
increasing an outflow set point of at least one other injector.
(0)An automated method for controlling fluid flow in a subsurface hydrocarbon-
containing
reservoir in which multiple wells are located, the multiple wells comprising:
multiple producers each configured to recover hydrocarbons from the
hydrocarbon-containing reservoir; and
an injector configured to provide an injection fluid into the hydrocarbon-
containing
reservoir at respective initial outflow set points;
the method comprising:
detecting an injection fluid breakthrough event in a breakthrough producer;
and
adjusting fluid flow within the hydrocarbon-containing reservoir and the
wells, the
adjusting comprising:
reducing an inflow set point of the breakthrough producer to reduce fluid
inflow from the hydrocarbon-containing reservoir;
increasing an inflow set point of at least one other producer; and
reducing an outflow set point of the injector identified as having over-
connectivity with the breakthrough producer.
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(P) In methods (L) to (0), reallocation of injection fluid to other fluids
and/or reallocation of
production via other production wells or zones/segments, can be controlled as
part of the
response to the breakthrough event. Reallocation of injection fluid can
include equally a
corresponding amount or rate of injection fluid compared to the reduced or
ceased injection
via the injector identified as having over-connectivity with the breakthrough
producer, to one
or more or all of the other injector wells or injection zones. The
reallocation of injection fluid
can also be done based on other factors such that different injector wells
and/or zones receive
different amounts or rates of reallocated injection fluid.
The methods and systems described above can also be combined depending on
various factors,
such as the particular multi-well arrangement to be controlled, the in situ
recovery process being
used, the particular structures used as the flow control assemblies, if
present, or the data that is
available as part of the flow control strategy.
Such control strategies could also be performed for wells that are each
operated periodically as
injector and producer, for example for huff-and-puff or cyclic steam
stimulation applications. In
such a case, one could rely on the control during injection stages to make
sure that flow was
evenly distributed to all zones of the well in injection mode, for example. In
this context,
breakthrough could be defined as breakthrough from an injector into a
particular zone in the
reservoir, as opposed to breakthrough from injector to producer. Breakthrough
would be detected
based on high flow rate to a zone or sudden increase in flow rate to a zone,
or some combination
of the two, for example. Breakthrough could also be detected retroactively in
the production
phase, based on high production rates as well as high water-oil ratio, and in
this case control
action would be applied in the next injection phase. Control action could be,
for example, reducing
flow rate set point to the breakthrough zone, and increasing flow rate set
point to non-
breakthrough zones, by some of the methods described above, particularly
natural re-allocation,
flow rate based method, distance from breakthrough zone, and so on.
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