CA2985953A1 - Enhancing hydrocarbon recovery or water disposal in multi-well configurations using downhole real-time flow modulation - Google Patents

Abstract

The technology generally relates to control strategies for multi-well systems for conducting water disposal or hydrocarbon recovery from subterranean reservoirs, such as methods and systems for real-time fluid flow monitoring and control in response to breakthrough events with reallocation of fluid flows.

Description

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.

2 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.

3 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.

4 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.

5 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

6 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.

7 (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

8 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

9 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.

10 - 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;

11 (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;

12 = 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:

13 (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.

14 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.

=
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;

= 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.

(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.

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 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.

(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;

(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.

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.

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.

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 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.

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.

(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 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 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 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 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:

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;

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.

(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.

Claims

CLAIM

1. A process for controlling fluid flow in multiple wells provided in a subterranean reservoir, the process comprising one or more features as described and/or illustrated herein.