Patent Publication Number: US-11649693-B2

Title: Handling produced water in a wellbore

Description:
FIELD OF THE DISCLOSURE 
     This disclosure relates to wellbores, in particular, to production wellbores. 
     BACKGROUND OF THE DISCLOSURE 
     Production wellbores are used for hydrocarbon production. Some production wellbores are placed in formations that have unwanted fluids such as water or gas. For example, production wellbores can be bounded by or in fluid communication with downhole water reservoirs or aquifers. Pressure changes in the formation can cause the unwanted fluids to mix with the hydrocarbons. During production operations, such unwanted fluids can be produced and brought to the surface of the wellbore. Managing these unwanted fluids can be costly and time-consuming. Methods and equipment for managing unwanted fluids are sought. 
     SUMMARY 
     Implementations of the present disclosure include a method that includes receiving, by a processing device and from one or more sensors coupled to a water reservoir storing water received from a separator, fluid information. The fluid information includes a water level of the water reservoir. The separator is fluidically coupled to a wellbore string disposed within a wellbore. The method also includes determining, based on the fluid information, operation mode instructions. The method also includes transmitting, to a controller communicatively coupled to at least one flow regulation device fluidically coupled to the wellbore string, the operation mode instructions. The controller controls, based on the instructions, the at least one flow regulation device to regulate, during a production mode of the wellbore string, a flow of production fluid from the wellbore string to the separator or regulating, during a water injection mode of the wellbore string, a flow of water from the water reservoir into the wellbore string. 
     In some implementations, the method also includes, before determining the operation mode instructions, comparing, by the processing device, the fluid information to a water level threshold. Determining the operation mode instructions includes determining, based on a result of the comparison, one of 1) instructions to initiate a production mode of the wellbore string, or 2) instructions to initiate a water injection mode of the wellbore string. 
     In some implementations, the one or more sensors include a first sensor and a second sensor, the fluid information including at least one of a high water level detected by the first sensor or a low water level detected by the second sensor, wherein determining the operation mode instructions includes determining one of 1) instructions to initiate the water injection mode based on the fluid information including a high water level, or 2) instructions to initiate the production mode based on the fluid information including a low water level. 
     In some implementations, at least one flow regulation device includes a first valve and a second valve. The first valve is attached to the wellbore string. The first valve resides at a production zone. The second valve is attached to the wellbore string and resides at a water injection zone. The controller is coupled to the first valve and the second valve. The controller is configured to 1) upon receiving instructions to initiate the water injection mode, close the first valve and open the second valve, allowing the water to be injected into the water injection zone through the wellbore string, and configured to 2) upon receiving instructions to initiate the water production mode, close the second valve and open the first valve, allowing the production fluid to flow through the wellbore string to the separator. 
     In some implementations, the controller is operationally coupled to a fluid pump fluidically coupled to the water reservoir and disposed upstream of the wellbore string. The controller activates, during the water injection mode, the fluid pump, flowing the water from the water reservoir to the wellbore string, and into the water injection zone. 
     Implementations of the present disclosure also include a wellbore assembly that includes a wellbore string disposed within a wellbore. The wellbore string extends from a surface of the wellbore to a downhole location of the wellbore. The wellbore includes a production zone and a water injection zone. The wellbore assembly also includes a separator disposed at the surface of the wellbore. The separator is fluidically coupled to the wellbore string and configured to receive, during a production mode of the wellbore assembly, production fluid from the wellbore string flown from the production zone. The separator separates water from the production fluid. The wellbore assembly also includes a water reservoir disposed at the surface of the wellbore and fluidically coupled to the separator and to the wellbore string. The water reservoir receives and stores, from the separator, the water separated from the production fluid. The water reservoir flows, to the wellbore string during an injection mode of the wellbore assembly, the water, allowing the wellbore string to flow the water to the water injection zone. 
     In some implementations, the water reservoir flows water to the wellbore string upon reaching a predetermined water level. In some implementations, the wellbore assembly also includes one or more sensors attached to the water reservoir, a controller, and a processing device disposed at or near the surface of the wellbore. The processing device is communicatively coupled to the controller and to the one or more sensors. The processing device receives, from the one or more sensors, fluid information including a water level in the reservoir. The processing device determines, based on the fluid information, a command to initiate the production mode or the water injection mode. The processing device transmits, to the controller, the command. The controller is coupled to at least one flow regulation device fluidically coupled to the wellbore string and configured to control, based on the command, the flow regulation device, regulating a flow of fluid from the wellbore string or into the wellbore string. In some implementations, the one or more sensors include a first sensor that detects a high water level in the reservoir and a second sensor that detects a low water level in the reservoir. The processing device determines, based on the fluid information including a high water level, a first command to initiate the water injection mode. The processing device determines, based on the fluid information including a low water level, a second command to initiate the production mode. 
     In some implementations, the wellbore assembly also includes a first valve and a second valve. The first valve is attached to the wellbore string and resides at the production zone. The second valve is attached to the wellbore string and resides at the water injection zone. The controller is coupled to the first valve and the second valve. The controller is configured to 1) upon receiving the first command to initiate the water injection mode, close the first valve and open the second valve, allowing the water to be injected into the water injection zone through the wellbore string, and configured to 2) upon receiving the second command to initiate the water production zone, close the second valve and open the first valve, allowing the production fluid to flow up the wellbore string to the separator. 
     In some implementations, the wellbore assembly also includes a pump fluidically coupled to the water reservoir and disposed upstream of the wellbore string. The pump flows the water from the water reservoir to the wellbore string and into the water injection zone. 
     In some implementations, the separator includes a portable separator and the water reservoir includes a portable water tank. 
     In some implementations, the wellbore includes a vertical portion and a non-vertical portion. The non-vertical portion extends from the vertical portion into the production zone, and the production zone is isolated from the water injection zone. 
     In some implementations, the wellbore includes a multi-lateral wellbore including a vertical wellbore, a first non-vertical wellbore extending from a first section of the vertical wellbore, and a second non-vertical wellbore extending from a second section of the vertical wellbore. The wellbore string includes a main wellbore string extending from the surface of the wellbore to a downhole location of the wellbore. The wellbore string also includes a production string fluidically coupled to and extending from the main wellbore string into the first non-vertical wellbore. The production string flows production fluid from the first non-vertical wellbore to the wellbore string. The water injection string is fluidically coupled to and extends from the wellbore string into the second non-vertical wellbore. The water injection string receives and flows water from the wellbore string to the second non-vertical wellbore. 
     In some implementations, the separator is fluidically coupled to the main wellbore string and receives, during the production mode and from the main wellbore string, the production fluid flown from the production string to the main wellbore string. The water reservoir is fluidically coupled to and is configured to flow, during the water injection mode, water to the main wellbore string, allowing the wellbore string to flow the water to the water injection string. 
     Implementations of the present disclosure also include a system that includes at least one processing device and a memory communicatively coupled to the at least one processing device. The memory stores instructions which, when executed, cause the at least one processing device to perform operations that include receiving, by a processing device and from one or more sensors coupled to a water reservoir storing water received from a separator, fluid information. The fluid information includes a water level of the water reservoir. The separator is fluidically coupled to a wellbore string disposed within a wellbore. The operations also include, based on the fluid information, determine operation mode instructions. The operations also include transmitting, to a controller communicatively coupled to at least one flow regulation device fluidically coupled to the wellbore string, the operation mode instructions. The controller controls, based on the instructions, at least one flow regulation device thereby regulating, during a production mode, a flow of production fluid from the wellbore string to the separator or regulating, during a water injection mode, a flow of water from the water reservoir into the wellbore string. 
     In some implementations, the operations further include, before determining the operation mode instructions: comparing, by the processing device, the fluid information to a water level threshold. Determining the operation mode instructions includes determining, based on a result of the comparison, one of 1) instructions to initiate a production mode of the wellbore string, or 2) instructions to initiate a water injection mode of the wellbore string. 
     In some implementations, the one or more sensors include a first sensor and a second sensor. The fluid information includes at least one of a high water level detected by the first sensor or a low water level detected by the second sensor. Determining the operation mode instructions includes determining one of 1) instructions to initiate the water injection mode based on the fluid information including a high water level, or 2) instructions to initiate the production mode based on the fluid information including a low water level. 
     In some implementations, the at least one flow regulation device includes a first valve attached to the wellbore string and residing at the production zone, and a second valve attached to the wellbore string and residing at the water injection zone. The controller is coupled to the first valve and the second valve. The controller is configured to 1) upon receiving instructions to initiate the water injection mode, close the first valve and open the second valve, allowing the water to be injected into the water injection zone through the wellbore string, and configured to 2) upon receiving instructions to initiate the water production zone, close the second valve and open the first valve, allowing the production fluid to flow through the wellbore string to the separator. 
     In some implementations, the controller is operationally coupled to a fluid pump fluidically coupled to the water reservoir and disposed upstream of the wellbore string. The controller is configured to activate, during the water injection mode, the fluid pump, flowing the water from the water reservoir to the wellbore string, and into the water injection zone. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG.  1    is a front schematic view of a wellbore assembly according to a first implementation of the present disclosure, the wellbore assembly in production mode. 
         FIG.  2    is a front schematic view of the wellbore assembly of  FIG.  1   , in water injection mode. 
         FIG.  3    is a front schematic view of a wellbore assembly according to a second implementation of the present disclosure, the wellbore assembly in production mode. 
         FIG.  4    is a front schematic view of the wellbore assembly of  FIG.  3   , in water injection mode. 
         FIG.  5    is a front schematic view of a wellbore assembly according to a third implementation of the present disclosure, the wellbore assembly in production mode. 
         FIG.  6    is a front schematic view of the wellbore assembly of  FIG.  5   , in water injection mode. 
         FIG.  7    is a flow chart of an example method of managing unwanted fluids in a production wellbore. 
         FIG.  8    is a schematic illustration of an example control system or controller for a wellbore assembly according to implementations of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION OF THE DISCLOSURE 
     The present disclosure describes a wellbore assembly or system for managing unwanted production fluids of a production wellbore. The wellbore assembly includes a separator, a water reservoir (e.g., a water tank), downhole valves, and a controller. The separator is connected to and receives production fluid from the wellbore string. The separator separates the produced water from the hydrocarbons near the wellhead and the water tank is used to temporarily store and reinject the water back into the water-bearing zone using the same production string. The controller controls the downhole valves to change the wellbore string between production and injection modes. The re-injected water can be disposed at a downhole downhole water reservoir or it can be injected near the hydrocarbon reservoir to rejuvenate the hydrocarbon reservoir. 
     Particular implementations of the subject matter described in this specification can be implemented so as to realize one or more of the following advantages. Recycling or re-injecting the water at the wellbore location can benefit the environment by eliminating the need of discharging the water to a nearby surface water body, or by eliminating the need of treating the water at a treatment facility. Increased field water production often requires a facility upgrade. The wellbore assembly of the present disclosure can help delay or eliminate the need to upgrade the field facilities and provide a cost-effective way of handling the excess water. Additionally, the wellbore assembly of the present disclosure can be installed in remote or hard-to-access wellbores in which installing a standalone water processing facility is no possible or is impractical. Re-injecting the water into the same wellbore can help revitalize the production of mature fields. The equipment used to re-inject the produced water can be portable, allowing the equipment to be quickly installed in newly drilled wells as well as old wells, such as wells that are candidates for sidetracking. Additionally, the wellbore assembly of the present disclosure can save time and resources by eliminating the need of drilling a separate disposal wellbore. 
       FIG.  1    shows a wellbore assembly  100  that includes a wellbore string  102  disposed within a wellbore  101  formed in a geologic formation  105 . The geologic formation  105  includes a hydrocarbon reservoir  107  from which hydrocarbons can be extracted, and a downhole water reservoir  109  (e.g., a water formation) into which water or other unwanted fluids can be injected. The hydrocarbon reservoir  107  and the water reservoir  109  can reside in a common formation later, they can reside next to each other, or they can be separated by one or more layers or reservoirs of the formation  105 . 
     The wellbore  101  extends from a surface  103  (e.g., a ground surface) of the wellbore  101  to a downhole end  133  of the wellbore  101 . The wellbore includes a production zone  117  and a water injection zone  119 . For example, the production zone  117  can be a zone or region at the wellbore  101  where hydrocarbons flow into the drill string  102 , and the water injection zone  119  can be a zone or region at the wellbore into which water can be injected from the wellbore string  102 . The wellbore  101  can include a vertical portion  131  that includes the water injection zone  119  and a non-vertical portion  132  that includes the production zone  117 . The production zone  117  of the wellbore  101  penetrates the hydrocarbon reservoir  107  and the water injection zone  119  penetrates the downhole water reservoir  109 . In some implementations, the water injection zone  117  and the production zone  117  can be in the same reservoir such as in the hydrocarbon reservoir  107 . 
     The wellbore  101  can include cased portions and open hole sections. For example, the vertical portion  131  of the wellbore  101  can be cased down to a casing shoe  128 . The rest of the vertical wellbore  131  can be an open hole section where water can penetrate or enter the water reservoir  109 . Similarly, the non-vertical portion  132  can include an open hole section where hydrocarbons can flow from the reservoir  107 . 
     The wellbore string  102  is used for both hydrocarbon production and water injection. The wellbore string  102  extends from the surface  103  of the wellbore to a downhole location of the wellbore at or near the downhole end  133  of the wellbore  101 . The wellbore string  102  can be a vertical string or, as shown and further described in detail below with respect to  FIGS.  3 - 6   , can include a vertical portion and a non-vertical portion. 
     The wellbore assembly  100  also includes packers  124  and  126  (e.g., an isolation packer that includes anchors and rubber elements) to isolate portions of the wellbore. For example, a first packer  124  forms, with a second packer  126 , an isolated region  150  or annulus where production fluid ‘F’ flows and can enter the wellbore string  102 . The production zone is part of the isolated region  150 . The second packer  126  separates the isolated region  150  from a second isolated region  151  where water can flow and enter the water injection zone  109 . The water injection zone  119  is part of the second isolated region  151 . 
     The wellbore assembly  100  also includes a piping system  160  (e.g., a portable or temporary piping system) that includes a separator  104  (e.g. a three-phase separator) and a water reservoir  106  (e.g., a water tank  113  disposed at the surface  103  of the wellbore  101 , a pond, a cistern, or a cased wellbore  146 ). The wellbore assembly  100  also includes a processing device  112 , a controller  114 , a first downhole valve  116  (e.g., an inflow control valve), and a second downhole valve  118  (e.g., an inflow control valve). Each of the first and second downhole valves  116  and  118  are communicatively coupled to the controller  112 . The wellbore assembly  100  can also include a first sensor  134  and a second sensor  136  attached to the water tank  113 , and a pump  108  fluidically coupled to and configured to flow water from the tank to the wellbore string  102 . 
     The processing device  112  can be a computer processor or other type of processing device. The processing device  112  is disposed at or near the surface  103  of the wellbore  101 . The processing device  112  is communicatively coupled to the controller  114  and to the sensors  134  and  136 . The processing device  112  and the controller  114  can be part of a common panel at the surface of the wellbore. Additionally, the controller  114  and the processing device  112  can be part of a common device or they can reside at separate locations. The processing device  112  receives, from the sensors  134  and  136 , fluid information that includes a water level in the tank  113 . The processing device  112  has logic or instructions to process the sensor information. The processing device  114  determines, based on the fluid information, a command or operation mode instructions to initiate a production mode or the water injection mode of the wellbore assembly  101 . 
     During the production mode, production fluid ‘F’ flows from the hydrocarbon reservoir  107  to the wellbore string  102  (e.g., through the inflow control valve  116 ), and from the wellbore string  101  to the separator  104 . Referring briefly to  FIG.  2   , during the water injection mode, water ‘W’ flows from the water reservoir  106  to the wellbore string  102 , and from the wellbore string  102  to the downhole water reservoir  109  (e.g., through the inflow control valve  118 ). 
     Still referring to  FIG.  1   , the processing device  112  transmits, to the controller  114 , the operation mode instructions. The controller  114  is communicatively coupled to the first downhole inflow control valve (ICV)  116  and the second downhole inflow control valve (ICV)  118 . During production mode, the controller  114  actuates or controls, based on the operation mode instructions, the valves  116  and  118  to regulating a flow of production fluid ‘F’ from the wellbore string  102  into the separator  104 . During water injection mode, the controller  114  actuates or controls, based on the operation mode instructions, the valves  116  and  118  regulating a flow of water ‘W’ from the water tank  113  into the wellbore string  102 . The controller  114  can also actuate the pump  108  and any other valves of the piping system  160  at the surface of the wellbore. 
     At the surface  103 , the piping system  160  resides near a wellhead  110  of the wellbore  101 . The wellbore string  102  extends downhole from the wellhead  110 . The wellhead  110  is fluidically coupled to the separator  104  through a fluid line  138 . The separator  104  is fluidically coupled to the water tank  113  through a water line  140 . The water tank  113  is fluidically coupled to the pump  108  through a water line  142 . The pump  108  is fluidically coupled to the wellhead  110  through a water line  144 . 
     As shown in dashed lines, in some implementations, instead or in addition to the water tank  113 , the water can be stored in a cased wellbore  146  (e.g., a water storage wellbore). The cased wellbore can have one or more sensors  154  that detect the water level inside the water wellbore  146 . The separator  104  can be fluidically coupled to the water storage wellbore  146  through a water line  121  and the water storage wellbore  146  can be fluidically coupled to the pump  108  through a water line  123 . 
     The downhole valves  116  and  118  can include inflow control valves or any type of flow regulation device, such as shifting sleeves. For example, valve  116  can be an inflow valve that received production fluid ‘F’ from the hydrocarbon reservoir  107 , and valve  118  can be an outflow valve that flows water ‘W’ to the downhole water reservoir  109 . During production, the inflow valve  116  can receive fluid from the hydrocarbon reservoir  107  and the outflow valve  118  can remain closed to prevent water from flowing up the wellbore string  102 . During water injection, the inflow valve  116  remains closed to prevent hydrocarbons from entering the wellbore string  102  and the outflow valve  118  remains open to flow water into the downhole water reservoir  109 . The downhole valves  116  and  118  are communicatively coupled to the controller  114  through a cable  122  or wirelessly. 
     As shown in  FIGS.  1  and  2   , the water reservoir  106  can be a water tank  113  (e.g., a portable water tank) or another type of water container. The water tank  113  can have a capacity that is at least four times the tubing capacity. The capacity of the tank  113  is large enough to allow the wellbore  101  to produce hydrocarbons for an extended period of time before having to switch to the water injection mode. The water tank  113  is used to store water until the water inside the tank reaches a certain level. Upon reaching such level, the water tank  113  flows the water to the wellbore string  102  during the water injection mode. When the wellbore assembly  102  switches to water injection mode, some water may be left in the wellbore string  102  and in the water lines  144  and  142  at the surface  103 . The size of the tank  113  is large enough to take the water left in these pipes and string  102 , while leaving enough room for more water received from the separator  104  during the production mode. The water tank  113  can be a portable tank that is quickly movable from one wellbore to another. The water tank  113  is fluidically coupled to the separator  104  and to the wellbore string  102 . The water tank  113  receives water from the separator  104  and stores the water temporarily. The water tank  113  flows, to the wellbore string  102 , the water, allowing the wellbore string  102  to flow the water to the water injection zone. Additionally, the separated water can be cleaned of emulsions/precipitates before reaching the water tank  113 . 
     The fluid pump  108  injects water from the tank  113  to the wellbore string  102 . The capacity of that pump  108  can be optimized such that the anticipated differential pressure needed for compression of the water is achieved to inject the water in the downhole water reservoir  109 . In some implementations, the water tank  113  can replace the use of a separate pump  108 . For example, the water tank  113  can include a hydro pneumatic tank that has an internal mechanism to move the water from the tank  113  to the downhole water reservoir  109 . Because pressurizing water is quicker and less costly than pressurizing gas, pressurizing the water to be injected can be accomplished quickly without the need of specialized equipment. 
     The sensors  134  and  136  can reside inside the tank or outside the tank  113 . The sensors  134  and  136  can include any type of sensing device that is capable of detecting the water level of the reservoir  106 . For example, a suitable sensor is the Rosemount 5300 Level Transmitter sold by Emerson in St. Louis, M.O., or the Tankbolt Automatic Water Level Controller sold by Oakter in National Capital Region Uttar Pradesh, India. In some examples, the sensors  134  and  136  can include external capacitance transmitters that sense an interface between water and air. 
     The sensors  134  and  136  are communicatively coupled to the processing device  112  to transmit, in or near real time, the fluid information representing the water level of the tank  113 . The first sensor  134  can detect a high water level in the tank  113  and the second sensor  136  can detect a low water level in the tank  113 . For example, the first sensor  134  can detect a presence of water and the second sensor  136  can detect a presence of air. In some implementations, the sensors  134  and  136  can detect fluidic pressure, or the tank  113  can include a floater or other type of mechanism to measure the water level inside the tank  113 . In some implementations, the second sensor  136  can reside at or near the bottom of the tank to detect when the water level is low enough to stop pumping water and initiate the production mode. In some implementations, the pump  108  can be configured to stop when the water pressure drops below a predetermined threshold. 
     In example implementations, “real time” means that a duration between receiving an input and processing the input to provide an output can be minimal, for example, in the order of seconds, milliseconds, microseconds, or nanoseconds, sufficiently fast to prevent the over-pressurization of the water tank  113 . 
     The controller  114  resides at or near the surface  103  of the wellbore and can control multiple devices (e.g., valves, pumps, and sensors) of the piping system  160 . In some implementations, the controller  114  can be disposed at the wellbore (e.g., near the valves  116  and  118 ) while still receiving the fluid information from the sensors  134  and  136 . In some implementations, the controller  114  can be implemented as a distributed computer system. The distributed computer system can be disposed partly at the surface and partly within the wellbore. The computer system can include one or more processors and a computer-readable medium storing instructions executable by the one or more processors to perform the operations described here. In some implementations, the controller  114  can be implemented as processing circuitry, firmware, software, or combinations of them. The controller  114  can transmit signals to the valve  116  and to lift hydrocarbons flowed into the wellbore and can transmit signals to the valve  118  to inject water flowed from the water tank  113 . 
     The first valve  116  is attached to the wellbore string  102  and resides at the production zone  117 . The production zone is bounded by and isolated with packers  124  and  126 . The non-vertical portion  132  of the wellbore  101  extends from the vertical portion  131  and is isolated from the water injection zone  119 . The second valve  118  is attached to the wellbore string  102  and resides at the water injection zone  119 . 
     The processing device changes between production mode and water injection mode based on the fluid information received from the sensors  134  and  136 . For example, the processing device  112  determines, based on the fluid information that includes a high water level, a first command to initiate the water injection mode. Conversely, the processing device  112  determines, based on the fluid information that includes a low water level, a second command to initiate the production mode. 
     Referring to  FIG.  2   , the controller  114  can, upon receiving the first command to initiate the water injection mode, close the first valve  116  and open the second valve  118 , allowing the water ‘W’ to be injected into the water injection zone  119  through the wellbore string  102 . As shown in  FIG.  1   , the controller  114  also can, upon receiving the second command to initiate the water production zone, close the second valve  118  and open the first valve  114 , allowing the production fluid ‘F’ to flow up the wellbore string  132  to the separator  104 . If needed, the wellbore assembly  100  can also include a mechanical formation isolation valve (MFIV)  120  to isolate the last section of the openhole portion  130 . 
     As shown in  FIG.  1   , during production mode, production fluid ‘F’ flows from the hydrocarbon reservoir  107  to the first valve  116  into the wellbore string  102 , from the wellbore string to the wellhead  110 , from the wellhead  110  to the separator  104 , and at the separator, water is separated from the production fluid ‘F’. In production mode, the water pump  108  is in standby or off, and no water is flown to the wellhead  110 . In production mode, the second valve  118  is closed to prevent any water from flowing back from the downhole water reservoir  109  that may mix with the production fluid ‘F’. 
     As shown in  FIG.  2   , during water injection mode, water ‘W’ flows from the water tank  113  to the pump  108 , from the pump  108  to the wellhead  110 , from the wellhead  108  to the wellbore string  102 , from the wellbore string  102  to the second valve  118  (or to a downhole outlet of the string  102 ), and from the second valve  118  to the downhole water reservoir  109 . In water injection mode, one or more valves at the surface prevent the flow of hydrocarbons from the separator  104  to the wellhead  110 . In production mode, the first valve  116  is closed to prevent production fluid ‘F’ from flowing into the wellbore string  102  while allowing water ‘W’ to flow down to the downhole water reservoir  109 . The water injected in the wellbore can stimulate the hydrocarbon reservoir  107 . 
     To change between production mode and injection mode, the processing device  112  determines, based on the fluid information from the sensors, the operation mode instructions. For example, the processing device can compare the fluid information to a water level threshold, and then, based on a result of the comparison, the processing device can determine instructions to initiate a production mode of the wellbore string, or determine instructions to initiate a water injection mode of the wellbore string. 
       FIGS.  3  and  4    illustrate a similar process to the one shown in  FIGS.  1  and  2   , but implemented with a different wellbore assembly  200  in a wellbore  201  that includes a lateral wellbore  232  drilled as sidetrack from a vertical wellbore  201 . For example, the lateral wellbore  232  can be drilled as a sidetrack from an existing old wellbore  201 . The lateral or non-vertical wellbore  232  can be drilled by deploying level  5  completion tools that can keep an access to the main wellbore  201 . The non-vertical wellbore  232  can be completed with multiple injection control devices (ICD)  221 , and ICV  216 , and a downhole valve  218  (e.g., a surface controlled bidirectional isolation valve to control fluid flow inside the tubing) residing downhole of the ICV  216 . The drill string  202  extends through a portion of the vertical wellbore  201  and into the lateral wellbore  232 . 
     The lower completion can be disposed in an open hole section of the lateral wellbore  232 . The open hole section can extend from a casing shoe  128 . The lower completion can include multiple ICDs  221 , with each ICD  221  disposed between respective isolation packers  141 . Each pair of adjacent packers  141  form an isolated annulus to isolate production zones of the lower completion. 
     As shown in  FIG.  3   , during production mode, the ICV  216  remains closed to prevent water from entering the wellbore string  202  while the bidirectional isolation valve (SFIV)  218  remains open to flow production fluid ‘F’ from the lower completion to the surface  103 . As shown in  FIG.  4   , during injection mode, the ICV  216  residing uphole of the SFIV  218  flows the water into the vertical wellbore  201  while the SFIV  218  remains closed to prevent water from flowing into the lateral wellbore  232  past the SFIV  218 . 
       FIGS.  5  and  6    illustrate a similar process to the one shown in  FIGS.  1  and  2   , but implemented in a multi-lateral wellbore  301 . The multi-lateral wellbore  301  can be implemented, for example, for horizontal producers that were placed in thick hydrocarbon reservoirs, in which new laterals are placed above the original hydrocarbon reservoir. In such cases, the “older” leg at the bottom can be converted into an intermittent water injection leg. 
     The multi-lateral wellbore  301  includes a vertical wellbore  320 , a first non-vertical wellbore  332  extending from a first section of the vertical wellbore  320 , and a second non-vertical wellbore  330  extending from a second section of the vertical wellbore  320 . The wellbore string  302  includes a main string section  334  extending from the surface of the wellbore to a downhole location  340  of the wellbore. The main wellbore string  304  can also include a non-verticals section  335  extending into the second non-vertical wellbore  330 . The downhole location  340  can reside at or near a downhole water reservoir  109 . The wellbore string  302  also includes a production string  336  fluidically coupled to and extending from the main wellbore string  334  into the first non-vertical wellbore  332 . The production string  336  flows production fluid from the first non-vertical wellbore  332  to the main wellbore string  334 . The wellbore string  302  also includes downhole valves  316  and  318  (e.g., ICVs, SFIVs, or a combination of the two). The first valve  316  can be disposed at the intersection of the main string  334  and the production string  336 . The first valve  316  can also include a three-way valve, a shifting sleeve, or a similar fluid control device. The valves can reside at the main wellbore string  334  or, similar to the embodiment shown in  FIG.  3   , one of the valves can reside at the production string  336 . 
     As shown in  FIG.  5   , during production mode, production fluid ‘F’ flows from the production string  336 , through the first valve  316 , and up the main wellbore string  302  to the surface  103 . During production mode, the second valve  318  remains closed to prevent production fluid from flowing into the lower portion of the main wellbore string  334 . As shown in  FIG.  6   , during injection mode, the first valve  316  prevents production fluid from entering the main wellbore  334  while allowing water ‘W’ to flow downhole into the non-vertical portion  335  of the main string  334 . The second valve  318  remains open to flow the water ‘W’ to the water reservoir  109  of the wellbore. 
     In some implementations, the water ‘W’ injected in the water-bearing injection zone (e.g., the downhole water reservoir) can stimulate the production in the hydrocarbon reservoir. For example, when the water “W’ is being injected in the same reservoir that bears the oil zone, the wellbore can feel the pressure of the water which, in turn, can enhance the hydrocarbon displacement through the production process. 
       FIG.  7    shows a flow chart of an example method  700  of managing unwanted fluids in a production wellbore. The method includes receiving, by a processing device and from one or more sensors coupled to a water tank storing water received from a separator, fluid information, the fluid information including a water level of the water tank, the separator fluidically coupled to a wellbore string disposed within a wellbore ( 705 ). The method  700  also includes determining, based on the fluid information, operation mode instructions ( 710 ). The method also includes transmitting, to a controller communicatively coupled to at least one flow regulation device fluidically coupled to the wellbore string, the operation mode instructions. The controller is configured to control, based on the instructions, at least one flow regulation device thereby regulating, during the production mode, a flow of production fluid from the wellbore string to the separator or regulating, during the water injection mode, a flow of water from the water tank into the wellbore string ( 715 ). 
       FIG.  8    is a schematic illustration of an example control system or controller for a flow meter according to the present disclosure. For example, the controller  800  may include or be part of the controller  114  shown in  FIGS.  1 - 6   , or may include or be part of the controller  114  and processor  112  shown in  FIGS.  1 - 6   . The controller  800  is intended to include various forms of digital computers, such as printed circuit boards (PCB), processors, digital circuitry, or otherwise. Additionally the system can include portable storage media, such as, Universal Serial Bus (USB) flash drives. For example, the USB flash drives may store operating systems and other applications. The USB flash drives can include input/output components, such as a wireless transmitter or USB connector that may be inserted into a USB port of another computing device. 
     The controller  800  includes a processor  810 , a memory  820 , a storage device  830 , and an input/output device  840 . Each of the components  810 ,  820 ,  830 , and  840  are interconnected using a system bus  850 . The processor  810  is capable of processing instructions for execution within the controller  800 . The processor may be designed using any of a number of architectures. For example, the processor  810  may be a CISC (Complex Instruction Set Computers) processor, a RISC (Reduced Instruction Set Computer) processor, or a MISC (Minimal Instruction Set Computer) processor. 
     In one implementation, the processor  810  is a single-threaded processor. In another implementation, the processor  810  is a multi-threaded processor. The processor  810  is capable of processing instructions stored in the memory  820  or on the storage device  830  to display graphical information for a user interface on the input/output device  840 . 
     The memory  820  stores information within the controller  800 . In one implementation, the memory  820  is a computer-readable medium. In one implementation, the memory  820  is a volatile memory unit. In another implementation, the memory  820  is a non-volatile memory unit. 
     The storage device  830  is capable of providing mass storage for the controller  800 . In one implementation, the storage device  830  is a computer-readable medium. In various different implementations, the storage device  830  may be a floppy disk device, a hard disk device, an optical disk device, or a tape device. 
     The input/output device  840  provides input/output operations for the controller  1000 . In one implementation, the input/output device  840  includes a keyboard and/or pointing device. In another implementation, the input/output device  840  includes a display unit for displaying graphical user interfaces. 
     Although the following detailed description contains many specific details for purposes of illustration, it is understood that one of ordinary skill in the art will appreciate that many examples, variations and alterations to the following details are within the scope and spirit of the disclosure. Accordingly, the exemplary implementations described in the present disclosure and provided in the appended figures are set forth without any loss of generality, and without imposing limitations on the claimed implementations. 
     Although the present implementations have been described in detail, it should be understood that various changes, substitutions, and alterations can be made hereupon without departing from the principle and scope of the disclosure. Accordingly, the scope of the present disclosure should be determined by the following claims and their appropriate legal equivalents. 
     The singular forms “a”, “an” and “the” include plural referents, unless the context clearly dictates otherwise. 
     As used in the present disclosure and in the appended claims, the words “comprise,” “has,” and “include” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps. 
     As used in the present disclosure, terms such as “first” and “second” are arbitrarily assigned and are merely intended to differentiate between two or more components of an apparatus. It is to be understood that the words “first” and “second” serve no other purpose and are not part of the name or description of the component, nor do they necessarily define a relative location or position of the component. Furthermore, it is to be understood that that the mere use of the term “first” and “second” does not require that there be any “third” component, although that possibility is contemplated under the scope of the present disclosure.